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Biological Services Program

FWS/OBS-77/12
March 1978

Environmental Planning
for Offshore Oil and Gas

Volume I:

Recovery
Technology

W ii 0 /^^

ECTiO^

Fish and Wildlife Service

U.S. Department of the Interior

The Biological Services Program was established within the U.S. Fish
and Wildlife Service to supply scientific information and methodologies on
key environmental issues that impact fish and wildlife resources and their
supporting ecosystems. The mission of the program is as follows:

• To strengthen the Fish and VJildHfe Service in its role as
a primary source of information on national fish and wild-
life resources, particularly in respect to environmental
impact assessment.

• To gather, analyze, and present information that will aid
decisionmakers in the identification and resolution of
problems associated with major changes in land and water
use.

• To provide better ecological information and evaluation
for Department of the Interior at/elopment programs, such
as those relating to energy development.

Information developed by the Biological Services Program is intended
for use in the planning and decisionmaking process to prevent or minimize
the impact of development on fish and wildlife. Research activities and
technical assistance services are based on an analysis of the issues a
determination of the decisionmakers involved and their information needs,
and an evaluation of the state of the art to identify information gaps
and to determine priorities. This is a strategy that will ensure that
the products produced and disseminated are timely and useful.

Projects have been initiated in the following areas: coal extraction
and conversion; power plants; geothermal , mineral and oil shale develop-
ment; water resource analysis, including stream alterations and western
water allocation; coastal ecosystems and Outer Continental Shelf develop-
ment; and systems inventory, including National Wetland Inventory,
habitat classification and analysis, and information transfer.

The Biological Services Program consists of the Office of Biological
Services in Washington, D.C., which is responsible for overall planning and
management;. National Teams, which provide the Program's central scientific
and technical expertise and arrange for contracting biological services
studies with states, universities, consulting firms, and others; Regional
Staff, who provide a link to problems at the operating level; and staff at
certain Fish and Wildlife Service research facilities, who conduct inhouse
research studies.

FWS/OBS-77/12
March 1978

Environmental Planning
for Offshore Oil and Gas

Volume I: Recovery Technology

John Clark, Jeffrey Zinn and Charles Terrell

The Conservation Foundation

1717 Massachusetts Avenue, N.W.

Washington, D.C. 20036

Contract No. 14-16-0008-962

Larry Shanks, Project Officer
National Coastal Ecosystems Team
National Space Technology Laboratories
NSTL Station, Mississippi 39529

Performed for

National Coastal Ecosystems Team
Office of Biological Services

Fish and Wildlife Service
U.S. DEPARTMENT OF THE INTERIOR

Environmental Planning for Offshore Oil and Gas

Volume

Recovery

Technology

Volume

II:

Effects

en Coastal Communities

Volume

III:

Effects

on Living Resources

and Habitats

Volume

IV:

Regulate

vy Framework for

Protecting Living Resources

Volume

Regional

Status Reports:

Part 1:

New England

Part 2:

Mid and South Atlantic

Part 3:

Gulf Coast

Part 4:

Cal ifot nid

Part 5:

Alaska, Washington and Oregon

This report should be cited thusly:

Clark, J., J. Zinn and C. Terrell. 1978. Environmental
Planning for Offshore Oil and Gas. Volume I: Recovery
Technology. The Conservation Foundation, Washington, D.C.
U.S. Fish and Wildlife Service, Biological Services Program,
FWS/OBS-77/12. 226 pp.

DISCLAiriER
The opinions, findings, conclusions, or recommenda-
tions expressed in this report/product are those of the
authors and do not necessarily reflect the views of the
Office of Biological Services, Fish and Wildlife Service,
U.S. Department of the Interior, nor does mention of trade
names or commercial products constitute endorsement or
recommendation for use by the Federal government.

ENVIRONMENTAL PLANNING FOR OFFSHORE OIL AND GAS
FOREWORD

This report is one in a series prepared by The Conservation Founda-
tion for the Office of Biological Services of the U.S. Fish and Wildlife
Service (Contract 14-16-0008-962). The series conveys technical informa-
tion and develops an impact assessment system relating'to the recovery
of oil and gas resources beyond the three-mile territorial limit of the
Outer Continental Shelf (OCS). The series is designed to aid Fish and
Wildlife Service personnel in the conduct of environmental reviews and
decisions concerning OCS oil and gas development. In addition, the
reports are intended to be as helpful as possible to the public, the
oil and gas industry, and to all government agencies involved with
resource management and environmental protection.

Oil and gas have been recovered for several decades from the Outer
Continental Shelf of Texas, Louisiana and California. In the future,
the Department of the Interior plans to lease more tracts, not only
off these coasts, but also off the frontier regions of the North, Mid-
and South Atlantic, eastern Gulf of Mexico, Pacific Northwest and Alaska.
Within the set of constraints imposed by the international petroleum
market (including supply, demand and price), critical decisions are made
jointly by industry and government on whether it is advisable or not to
move ahead with leasing and development of each of the offshore frontier
areas. Once the decision to develop a field is made, many other deci-
sions are necessary, such as where to locate offshore platforms, where
to locate the onshore support areas, and how to transport hydrocarbons
to market.

Existing facilities and the size of the resource will dictate
which facilities will be needed, what the siting requirements will be,
and where facilities will be sited. If the potential for marketable
resources is moderate, offshore activities may be staged from areas
already having harbor facilities and support industries; therefore,
they may have little impact on the coast adjacent to a frontier area.
An understanding of these options from industry's perspective will
enable Fish and Wildlife Service personnel to anticipate development
activities in various OCS areas and to communicate successfully with
industry to assure that fish and wildlife resources will be protected.

The major purpose of this report is to describe the technological
characteristics and planning strategy of oil and gas development on
the Outer Continental Shelf, and to assess the effects of OCS oil and
gas operations on living resources and their habitats. This approach
should help bridge the gap between a simple reactive mode and effec-
tive advanced planning--planning that will result in a better
understanding of the wide range of OCS activities that directly and
indirectly generate impacts on the environment, and the counter-
measures necessary to protect and enhance living resources.

Development of offshore oil and gas resources is a complex
industrial process that requires extensive advance planning and
coordination of all phases from exploration to processing and ship-
ment. Each of hundreds of system components linking development
and production activities has the potential for adverse environ-
mental effects on coastal water resources. Among the advance
judgements that OCS planning requires are the probable environ-
mental impacts of various courses of action.

The relevant review functions that the Fish and Wildlife Service
is concerned with are: (1) planning for baseline studies and the
leasing of oil and gas tracts offshore and (2) reviewing of permit
applications and evaluation of environmental impact statements (EIS)
that relate to facility development, whether offshore (OCS), near
shore (within territorial limits), or onshore (above the mean high
tidemark). Because the Service is involved with such a broad array
of activities, there is a great deal of private and public interest
in its review functions. Therefore, it is most valuable in advance
to have some of the principles, criteria and standards that provide
the basis for review and decisionmaking. The public, the offshore
petroleum industry, and the appropriate Federal, state, and local
government agencies are thus able to help solve problems associated
with protection of public fish and wildlife resources. With
advanced standards, all interests should be able to gauge the
environmental impacts of each OCS activity.

A number of working assumptions were used to guide various
aspects of the analysis and the preparation of the report series.
The assumptions relating to supply, recovery, and impacts of offshore
oil and gas were:

1. The Federal Government's initiative in accelerated
leasing of OCS tracts will continue, though the pace
may change.

2. OCS oil and gas extractions will continue under private
enterprise with Federal support and with Federal
regulatfbn.

3. No major technological breakthroughs will occur in the near
future which could be expected to significantly change the
environmental impact potential of OCS development.

4. In established onshore refinery and transportation areas,
the significant impacts on fish and wildlife and their
habitats will come from the release of hydrocarbons during
tanker transfers.

5. A significant potential for both direct and indirect impacts
of OCS development on fish and wildlife in frontier areas

is expected from site alterations resulting from develop-
ment of onshore facilities.

6. The potential for onshore impacts on fish and wildlife
generally will increase, at least initially, somewhat in
proportion to the level of onshore OCS development activity.

The assumptions related to assessment of impacts were:

1. There is sufficient knowledge of the effects of OCS develop-
ment activities to anticipate direct and indirect impacts

on fish and wildlife from known oil and gas recovery systems.

2. This knowledge can be used to formulate advance criteria for
conservation of fish and wildlife in relation to specific
OCS development activities.

3. Criteria for the protection of environments affected by
OCS-related facilities may be broadly applied to equivalent
non-OCS-related facilities in the coastal zone.

The products of this project--reported in the series Environ-
mental Planning for Offshore Oil and Gas--consist of five technical
report volumes. The five volumes of the technical report series are
briefly described below:

Volume I Reviews the status of oil and gas resources of the
Outer Continental Shelf and programs for their
development; describes the recovery process step-
by-step in relation to existing environmental
regulations and conservation requirements; and
provides a detailed analysis for each of fifteen
OCS activity and facility development projects
ranging from exploration to petroleum processing.

Volume II Discusses growth of coastal communities and effects
on living resources induced by OCS and related
onshore oil and gas development; reports methods
for forecasting characteristics of community develop-
ment; describes employment characteristics for
specific activities and onshore facilities; and
reviews environmental impacts of probable types of
development.

Volume III Describes the potential effects of OCS development
on living resources and habitats; presents an., inte-
grated system for assessment of a broad range of
impacts related to location, design, construction,
and operation of OCS-related facilities; provides a
comprehensive review of sources of ecological
disturbance for OCS related primary and secondary
development.

Volume IV Analyzes the regulatory framework related to OCS
impacts; enumerates the various laws governing
development offshore; and describes the regulatory
framework controlling inshore and onshore buildup
in support of OCS development.

Volume V In five parts, reports current and anticipated OCS
development in each of five coastal regions of the
United States: New England; Mid and South Atlantic:
Gulf Coast; California; and Alaska, Washington and
Oregon.

John Clark was The Conservation Foundation's project director for
the OCS project. He was assisted by Dr. Jeffrey Zinn, Charles Terrell
and John Banta. We are grateful to the U.S. Fish and Wildlife Service
for its financial support, guidance and assistance in eyery stage
of the project.

William K. Reilly

President

The Conservation Foundation

ENVIRONMENTAL PLANNING FOR OFFSHORE OIL AND GAS

PREFACE

This report is presented in two parts. Part 1 introduces the
offshore oil and gas industry, starting with the demand for energy and
available resources and leading to the current national program to
develop offshore oil and gas. Part 2 discusses the specific offshore
and onshore activities involved in the recovery of offshore oil and gas,
and describes in detail each of fifteen major development phases along
with related activities and facilities. For each activity/facility
development type the site requirements are described, along with con-
struction and operation, community factors, effects on living resources,
and regulatory factors. The report gives particular attention to the
strategies the Outer Continental Shelf (OCS) industries use in making
investment, location, and timing decisions.

While the goal of the whole OCS project is to provide a basis for
assessing the broadest range of direct and induced impacts on resources
within the jurisdiction of the U.S. Fish and Wildlife Service, Volume I
is mainly concerned with physical description of offshore oil and gas
development activities as (1) a direct cause of impacts offshore and
(2) a generator of indirect impacts inshore and onshore.

The report discusses where the oil industry's activities are
currently located, where future efforts are planned, where known natural
resources are located, where the most promising new fields may be found,
where seismic surveying operations are currently focused, where drilling
is anticipated, and where pipelines, transshipment terminals and refineries
are being planned and built. The extent to which the United States will
depend on imported products and where and how these products will enter
the United States are briefly discussed.

The information in this report was collected from a wide variety of
sources: the coastal document center of The Conservation Foundation;
other libraries and relevant literature sources; unpublished files; data
exchange with other ongoing OCS studies; and interviews and direct field
observations. To the extent possible, the information is current to
mid-year 1976.

TABLE OF CONTENTS

ENVIRONMENTAL PLANNING FOR OFFSHORE OIL AND GAS
VOLUME I: RECOVERY TECHNOLOGY

Page

FOREWORD ■"

PREFACE ..y

LIST OF FIGURES ^^^^

LIST OF TABLES ,^]

ACKNOWLEDGEMENTS x'""'!

Part 1 RESOURCES AND RECOVERY I

1.1 Petroleum Demands and Resources 2

1.1.1 National Demand and Supply of Energy 3

1.1.2 Status of U.S. Oil and Gas Resources 4

1.1.3 U.S. Production Trends 6

1.1.4 Offshore Production and Activity 7

1.1.5 Worldwide Resources and Production Trends • • • 9

1.1.6 Location of Refineries and Other Infrastructure. 9

1.1.7 Natural Gas 12

1.2 Problems and Potentials of Offshore Development. 13

1.2.1 The Continental Shelf 14

1.2.2 Exploration and Discovery 15

1.2.3 Geologic Potential of Lease Areas 18

1.2.4 Offshore Oil and Gas Resources 21

1.2.5 Offshore Production Goals and Potentials .... 23

1.3 Scheduling of Offshore Development 27

1.3.1 Geologic Indications 27

1.3.2 Phases of Development 28

1.3.3 Time Constraints 34

Part 2 OCS DEVELOPMENT SYSTEMS - INTRODUCTION AND GUIDE 38

2.1 Factors of Influence ^^

2.1.1 Community Factors -- Indirect Effects 44

2.1.2 Effects on Living Resources 45

2.1.3 Regulatory Factors J7

2.1.4 Industry Decision Factors 50

latiU^ of Contents (Continued)

.:.\1 Offshore Development Projects 57

.\^.\ Geophysical Surveying 58

:..2.2 Exploratory Drilling 63

:.:.3 Production Drilling 76

:.:.4 Pipelines 88

c:.:.5 Offshore Mooring and Tanker Operations 106

:.3 Onshore Development Projects 119

:.3.1 Service Bases 120

:.3.2 Marine Repair and Maintenance 134

2.3.3 General Shore Support 142

2.3.4 Platform Fabrication Yards 150

2.3.5 Pipe-coating Yards ]^l

2.3.6 Oil Storage Terminals '68

2.4 Processing and Manufacturing Projects 179

2.4.1 Refineries ISO

2.4.2 Petrochemical Industries 194

2.4.3 Gas Processing 204

2.4.4 Liquefied Natural Gas (LNG) Processing Plants . . 212

F.eftrences
Plate I

222

Figure

LIST OF FIGURES

Paae

Petroleum resource terms and classification system 5

An example profile of the continental margin 14

Mercator projection of the oceans and seas of

the worl d 16

Example of geological traps 17

Development status of U.S. offshore basins 19

OCS process chart 29,30

Relationships of phases of field development to

facility project operations 41

Project implementation schedule (sample) 43

Seismic operations 59

Exploratory drilling, project implementation schedule 63

Jack-up drilling rig for offshore exploration 66

Semi -submersible drilling rig for offshore exploration 68

Typical dynamic positioned deep water drill ship 69

Production drilling, project implementation schedule 76

Example of a fixed-pile platform 78

Typical directional ly drilled wells 79

Continual technological improvements 81

Pipelines, project implementation schedule 88

Offshore pipe-laying barge 94

"Bury barge" or pipeline dredge barge 94

Directional drilling for pipeline installation

under ri vers and streams 95

"Fi gure Page

22 Offshore mooring, project implementation schedule 106

23 Controlling water depths at major

Uni ted States ports 1 08

24 Simplified schematic of offshore facilities.

single point mooring system 109

25 Catenary Anchor Leg System (CALM) 109

26 Single Anchor Leg Mooring (SALM) 110

27 Service base, project implementation schedule 121

28 Site plan for comprehensive supply and service base,

Lerwick, Shetland Islands 123

29 Staging area requirements of offshore activities 129

30 Marine repair and maintenance, project implementation

schedul e 1 34

31 Characteristics of typical support vessels 136

32 General shore support, project implementation

schedul e 1 42

33 Platform fabrication yard, project implementation

schedule 150

34 Site plan for Brown and Root platform fabrication

yard at Cape Charles in Northampton County, Virginia... 153

35 Pipe-coating yard, project implementation schedule 162

36 Oil storage, project implementation schedule 168

37 Schematic layout for a typical surge tank farm 170

38 Refinery, project implementation schedule 180

39 Example: refinery flow scheme 186

40 Petrochemical industries, project implementation

schedule 194

41 Gas processing, project implementation schedule 204

Figure Page

42 A flow diagram of natural gas processing

operati on 207

43 Liquefied natural gas processing plants,

project implementation schedule 212

44 LNG vaporizer 216

45 Flow diagram of Elba Island LNG facility 217

46 Proposed design of offshore LNG plant 221

LIST OF TABLES

Table Page

1 Distribution of U.S. Energy Supply,

1 950-1 990 4

2 Projected U.S. Oil and Gas Production to the Year 1990 6

3 U.S. Offshore Oil and Gas Production in Relation to

Total Production, 1960-1974 8

4 Estimates of "Undiscovered Recoverable" Resources,

or Predicted Potential Yields From the Offshore 22

5 Proposed OCS PI anni ng Schedul e 25

6 Offshore Acreage to be Made Available for Leasing 26

7 Federal Laws Relevant to U.S. Fish and Wildlife

Service Responsibilities 48

8 Offshore Exploration Drilling Expenditure Index

Comparing Gulf of Mexico to Other Areas 55

9 Present and Future Water Depth and Earliest Dates for

Exploration Drilling and Production for the U.S.

Outer Continental Shelf Areas 56

10 Advantages and Disadvantages of Major Types of Mobile

Exploratory Offshore Drilling Rigs 71

11 Regulatory Responsibilities for Pipelines 101,102

12 Some Vessels Used in Offshore Petroleum

Recovery Activities 135

13 Major OCS Support Companies and Average Employment

Figures 143

14 Industry Estimates of Onshore Facility Requirements for

OCS Oil and Gas Operations in the Baltimore Canyon 146

15 Refinery Tankage Requirements Related to Storage

Location and Throughput (Barrels) 171

16 Approximate Land Requirements for Surge Tank Farms 172

Table Page

17 Capacity of Principal United States

Refining Regions '^^

18 Refineries Planned but Not Constructed 191

19 Estimated Water Requirements for a Representative
Petrochemical Complex 197

20 Estimated Future Water Pollution Loadings of a
Representative Petrochemical Complex 200

21 Relative Ranking of Regions by Location Factor for Future
Primary Organic Chemical Development 202

ACKNOWLEDGEMENTS

Staff of The Conservation Foundation who assisted ably with
preparation of Volume I include Thomas Ballentine, John Banta, Charles
Terrell, Sarah Brooks, Nancy Carter, Ray Lark and Ray Tretheway. Major
institutional review and editorial guidance was provided by Dr. J.
Clarence Davies, Executive Vice President. Mrs. Laura O'Sullivan was
supervisor of manuscript production and Ms. Claudia Wilson was graphics
and design director.

Consultants who made a major input include David C. Williams,
principal technical editor, and Oscar Strongin, principal technical
advisor on OCS development. Other consultants who generously assisted
with review and editing include Drs. Marc Hershman, Joel Goodman, Anthony
Mumphrey, Ruth Corwin, and Virginia Tippie, assisted by James Feldman,
Peter Klose, Gino Carlucci, Patrick Heffernan and Don Robodne respectively.

Colleagues who generously contributed their time to review drafts
or assist iri other ways include Suzanne Reed, Office of Planning and
Research, California Governor's Office, and Michele Tetley, Information
Center Director of the Office of Coastal Zone Management. Wilson Laird
and Keith Hay, plus other staff members of the American Petroleum Institute,
were helpful in locating resources and answering specific technology-
related questions. Dr. Frank Gregg, Vincent Ciampa and Irvin Waitsman
of the New England River Basins Commission provided information, helpful
criticisms and reviews of draft material.

The authors are grateful for the guidance provided by the Office of
Biological Services of the U.S. Fish and Wildlife Service, particularly
Drs. Allan Hirsch, William Palmisano and Howard Tait. Larry Shanks of
that office was especially helpful with substantive aspects of the work,
with painstaking editorial assistance, and with coordination of the
manuscript review process.

We are most appreciative for the assistance of the following U.S.
Fish and Wildlife Service reviewers who commented on draft products:
James Barkuloo (Panama City) Office of Biological Services; Dr. Lee
Barclay (Galveston) Office of Biological Services; Galveston Field
Office of Ecological Services; Drs. Jay Watson and John Byrne (Portland,
Oregon) Office of Biological Services; Larry Salaski, (Washington, D.C.)
Office of Biological Services; Larry Goldman (Washington, D.C.) Office
of Ecological Services; Dr. Burt Brun (Annapolis, Maryland) Office of
Biological Services; Richard Huber, (Minneapolis) Office of Biological
Services. Other Department of the Interior colleagues who reviewed
drafts were Bud Damaburgher, U.S. Geological Survey Branch of Marine Oil

and Gas; Dr. Bill Van Horn, Bureau of Land Management; Al Powers, Department
of the Interior Office of OCS Coordination.

John Clark and Jeffrey Zinn

Senior Associates

The Conservation Foundation

XIV

PART I -- RESOURCES AND RECOVERY

Section 1.1 presents forecasts for demands on the potential supply
of energy to the year 2000. Petroleum resources to meet that demand
are estimated for the nation, both onshore and offshore. United States
production trends, now declining, have had a strong effect on worldwide
resource and production trends. Production locations have been the
primary factor in locating oil refineries and petroleum infrastructure,
discussed in the conclusion of this section.

Section 1.2 discusses the offshore development potentials, pro-
blems and programs including the geologic potential of the continental
shelf and of proposed lease areas. Offshore resource estimates are
presented, followed by the schedule for the Federal program to lease
and develop the Outer Continental Shelf.

Section 1.3 introduces the six major phases involved in the off-
shore development process--pre-exploration, geological and geophysical
exploration, exploratory drilling, field development, production and
shutdown of facilities--and time constraints on industry development.

1 . 1 PETROLEUM DEMANDS AND RESOURCES

It is widely accepted that the major source of domestic energy
during the next quarter of a century will be oil and gas. New energy
sources appear too expensive and pollution prone to meet a significant
portion of domestic energy needs at present despite the efforts made to
develop them. An era characterized by abundant and cheap energy has
ended, and the world is undergoing a painful readjustment characterized
by increasing demand and reduced supplies of energy.

This section presents the overall national demand for energy supply
and the anticipated role of oil and gas in meeting these demands through
the year 2000. The amount of petroleum resources--and domestic
production--are now declining, especially onshore. This has led to a
larger share of production for offshore oil and gas. Worldwide, the
increased demand and decreased supply in the United States has led to
dramatic shifts in resources and production from the Western Hemisphere
to the Eastern--especially the Middle East.

Since the first commercial oil well was drilled in Pennsylvania in
1859, petroleum has been a significant factor in our nation's growth and
development. Oil did not replace coal as the primary U.S. energy source
until the 1940' s, but even before that, it was a critical commodity and
played a vital role in national changes in lifestyle. In the past 30
years, the value of petroleum has spread far beyond fuels. It has
become a required ingredient for a broad range of standard commodities
from drugs to plastics and synthetic fibers.

1.1.1 National Demand and Supply of Energy

For 100 years the United States was blessed by an abundance of
petroleum resources. But in recent years our reserves have shrunk
drastically as our rate of consumption has surpassed our ability to
produce from domestic sources. Until 1948, the United States was a net
exporter of petroleum, but since then our consumption has exceeded
domestic production. At present, our nation is dependent on petroleum
imports for over 40 percent of our oil demand. The percentage of
imports is predicted to increase to over 50 percent before the end of
the 1970's.

Two other factors are expected to have significant effects on
energy source options: (1) the percentage of imports may increase even
further if other fuel sources such as coal or nuclear power are produced
at a slower rate than predicted and, (2) more than half of the domestic
production of oil and gas that will be consumed during this century must
be derived from new and as yet unknown resource deposits.

The Federal Energy Administration (FEA) forecasts that nuclear
power plants will not be built as rapidly as had been projected in the
past. According to FEA [1] coal production should rise by 1985, perhaps
exceeding 1 billion tons (compared to 639 million tons in 1974).

Solar energy, which has been widely heralded as the new energy
source of the future, is expected to account for not more than 10
percent of the total U.S. energy supply by the year 2000 and up to 45
percent in 2020 according to the U.S. Energy Research and Development
Administration (ERDA). Other sources of energy such as wind and geo-
thermal are not predicted to contribute more than a few percent.

While oil and gas may remain the dominant fuels for the next 25
years in the United States, their share of the total energy supply is
expected to drop from the present 76 percent to 59 percent by the year
2000, as shown in Table 1. Use of coal will remain relatively constant,
while both nuclear and solar DOwer should increase their shares. Table 1
indicates the projected ratio of the domestic energy supply sources for
the period 1975-2000. The projection for the year 2000 uses a recent
forecast by the Exxon Corporation [2] and incorporates other information
to predict the situation at the end of the century.

Table 1. Distribution of U.S. Energy Supply, 1950-1990
(in Percent of BTU's). (Sources: 1950 Data, Reference
2; 1975-1990 Data, Reference 1)

YEAR

Source

1950

(%)

1975 1980

(%) (%)

1990

Nuclear

2 6

Hydro/Geothermal

4 4

Coal

18 19

Gas

29 22

Oil

47 49

Solar

0 0

1.1.2 Status of U.S. Oil and Gas Resources

Cumulative production of oil in the United States from 1849 through
1974 amounted to 106.1 billion barrels, according to the U.S. Geological
Survey [3]. The amount of oil remaining has been estimated by USGS, by
classifications shown in Figure 1. Identified reserves are estimated to
be 68 billion barrels (statistical mean of high and low estimates), or
63 percent of the total already produced. USGS has further estimated
"undiscovered recoverable resources," those economic resources not yet
discovered which are estimated to exist in favorable geological environ-
ments, to range between 50 and 127 billion barrels of oil. The statistical
mean of these estimates is 86 billion barrels.

In comparison to the 481 trillion cubic feet of natural gas produced
through 1974, there are identified reserves of 439 trillion cubic feet
and undiscovered recoverable resources of 484 trillion cubic feet
(statistical means). The latter estimate has a range between 322 and
655 trillion cubic feet of natural gas [3].

While these estimates indicate a supply available for many years,
the level of proven reserves--which increased for many years with new

discoveries--has been declining recently. Consumption has been rising
faster than discoveries. In 1975 (the latest information available) oil
reserves declined by about 5 percent, and natural gas reserves declined
nearly 4 percent.

Figure 1. Petroleum resource terms and classification
system (Source: References),

IDENTTIRED

Demonstrated

Measured

Indicated

Inferred

UNDISCOVERED

RESERVES

RESOUllt-ilf'"-

■ncreasing degree of geologic assurance

1. Resources - naturally occurring materials
concentrated so that economic extraction is
potentially feasible.

2. Reserves - that portion of resources which are
presently economically extractable.

3. Undiscovered recoverable resources - those
economic resources yet undiscovered which are
estimated to exist in favorable geologic
environments.

The present poor condition of our natural petroleum resource is
well demonstrated by the critical declines in the big, Gulf of Mexico
producing states, Texas and Louisiana. Texas, the leading U.S. oil
producer since 1928, which presently produces over 40 percent of the
Nation's crude oil, has seen its measured reserves of crude drop from a
peak of 13.0 billion barrels in 1971 to 10.1 billion barrels as of
January 1, 1975. Louisiana's measured reserves have declined from 5.7
billion barrels in 1970 to 3.8 billion barrels in 1975.

1.1.3 U.S. Production Trends

While U.S. crude production slumped in the mid-1970's, industry has
forecast a long term increase in production until 1990 (Table 2), but it is

Table 2. Projected U.S. Oil and Gas Production to the
Year 1990 in Millions of Barrels Per Day (Two Trillion
Cubic Feet of Gas/Year Equals One Million Barrels/Day
Oil Equivalent) (Source: Reference 2)

Year

Production

1975

1980

1990

Oil Production

Conventional

10.6

10.8

11.8

2
Non-conventional

0.0

0.1

1.6

Imports

6.3

10.6

12.0

16.9 21.5 25.4

Gas Production 1975 1980 1990
Conventional

20.7

16.2

19.3

0.2

0.5

2.2

1.0

2.0

3.5

3
Synthetic

Imports

Subtotal 21.9 18.7 25.0

1. Oil and gas fields tapped by drilling wells.

2. Oil created from oil shale or coal liquification.

3. Gas created from coal gasification.

believed that thereafter there will be a progressive decline. This may
be offset to some extent by non-conventional ("synthetic") oil derived
from oil shale and coal. Conventional gas supplies have been forecast
to decline up to 1980, then increase until 1990 as new fields are
discovered. There will then be a period of continued decline into the
twenty first century. Similar to oil, it is anticipated that synthetic
gas from coal (along with increased imports, mostly in the form of
liquefied natural gas), may take up the slack in domestic output.

While the projected supply of "conventional" domestic oil and gas
is relatively constant, production from existing known reserves will
decline; the balance will be made up by new discoveries. It is believed
that by 1990, production from existing known oil reserves will amount to
only 5 million barrels per day and that production from existing known
gas reserves will amount to only 8 trillion cubic feet (Tcf) per year or
4 million-barrels-per-day oil-equivalent. It is expected that as much
as 40 to 50 percent of the new discoveries will be offshore fields and
the total offshore production will rise accordingly.

1,1.4 Offshore Production and Activity

While exploration of land areas will be vigorously pursued, the
offshore area represents the "last frontier" in U.S. petroleum explora-
tion. In the past 15 years the United States has so greatly accelerated
offshore oil and gas development that it now accounts for a substantial
part of total domestic output. Many trends can be discerned from the
data presented in Table 3 which shows the domestic total and offshore
oil and gas production from 1960 to 1974,

Total onshore and offshore oil production increased incre-
mentally from 1960 to 1970 but now has declined from that peak period
by about 20 percent.

The significance of offshore oil to the total domestic supply
picture is indicated by a comparison of its contribution of 4 percent
in 1960 to the more than 18 percent in 1973, Offshore oil production
quadrupled during the 1960's, peaked in the early 1970's and then
declined about 7 percent. The production of offshore natural gas
showed an even more impressive growth. It increased almost sevenfold
in the 1960-69 period, reached a maximum in 1971, and since that time
has declined by about 30 percent.

It is generally conceded that offshore production will account for
an ever-increasing percentage of total U.S. production; within the next
15 to 25 years offshore petroleum may account for as much as 40 to 50
percent of all domestic production. In U.S. offshore areas there were
1,029 wells and 1,128 wells drilled, respectively, in 1973 and 1974.
The number of wells drilled in recent years has remained below
1,000. While these statistics indicate that there may be no overall

increase in U.S. offshore drilling, activities could increase significantly
in frontier areas where drilling has not yet occurred if large discoveries
are made.

Table 3. U.S. Offshore Uil and Gas Production in Relation
to Total Production, 1960-1974 (Source: Reference 4)-

Crude Oil Production

Matural Has

Production

■i Offshore

1, OtfsTwre

Total

Offshore

To Total

Total

Offshore

To Total

(millions

of barrels)

[billions

of ciiic

feet)

I960

2907

117

4.0

13088

440

2.9

1961

2984

153

4.5

15460

478

3.1

1962

3049

162

5.3

16039

640

4.0

1963

3154

188

6.0

16973

763

4.5

1964

3201

215

6.7

17440

350

4.9

1965

3290

243

7.4

17963

939

5.2

1966

3496

298

8.5

19034

1372

7.2

1967

3730

352

9.4

20252

1830

9.1

1968

3869

419

10.8

21325

2299

10.8

1969

3959

465

11.7

22679

2800

12.4

19"0

4123

506

12.3

23787

31,36

13.2

1971

4101

549

13.4

24104

3667

15.2

1972

3450

472

13.7

22897

3325

14.5

1973

3361

620

18.4

22854

2603

11.4

1974

3199

521

16.3

22377

2574

10.6

1.1.5 Worldwide Resoij-rces and Production Trends

Of all the trends occurring in the worldwide petroleum business,
the most important is the current shifting of measured reserves and
production from the U.S. and Western Hemisphere to the Eastern
Hemisphere--the Persian Gulf nations, the western and northern African
nations, and Indonesia along with several other Southeast Asian countries.
All of these areas are presently supplying significant imports to the
United States. The dramatic North Sea and Prudhoe Bay discoveries have
caused a temporary increase in the United States and Western European
supply.

Over 85 percent of the world's hydrocarbon production and reserves
occur in less than 5 percent (238 fields) of all producing accumulations
[5]. Sixty-five percent of the reserves occur in less than one percent
of the fields. The 55 "supergiant" fields (scattered throughout the
world) each contain over a billion barrels of oil (or a trillion cubic
feet of natural gas). Fifteen percent of reserves occur in two immense
Persian Gulf fields--Ghawan in Saudi Arabia and Burgan in Kuwait.

More than anything else, the shift in the geographical location of
reserves and production has meant, and will mean, a transition from
traditional patterns of production, transportation, and refining of
nydrocarbons to new patterns with oil and gas flowing from the reserve
rich countries to U.S. refining and distribution centers. It is these
patterns, defined by the worldwide flow of Eastern Hemisphere oil and
gas, which will determine the trends in the U.S. petroleum infrastructure
for at least the next 20 years. Unless an unexpectedly large reserve is
found offshore in U.S. frontier areas, any discoveries or production
from the offshore will not alter the trends set by foreign imports
(imports, however, could be affected by significant conservation efforts).
Domestic production from offshore will simply displace foreign hydrocarbons
to other regions of the nation or be added to a region's input stream.
Therefore, vast growth of refining and distribution systems will not
likely be induced by offshore finds, unless they are unexpectedly high.

1.1.6 Location of Refineries and Other Infrastructure

The easiest way to explain how the infrastructure of the U.S. oil
industry is presently distributed is to say that it is organized around
the historical sources of oil and gas, areas which have had the largest
concentration of producing fields. Therefore, the heaviest concentrations
of infrastructures are in the Texas and Louisiana coastal region. The
pipelines and refineries in these areas have, in the past, been supplied
from local fields but now are increasingly supplied from imports coming
in through the region's many tanker terminals.

How offshore development in any "frontier" area will affect nearby
coastal communities depends on its relation to the existing pattern of

industry infrastructure. Particularly important is the geography of
crude oil pipelines, transshipment terminals, refineries, product pipelines,
and the technical and business organizations that build and operate such
facilities. Existing infrastructure is of great importance because
it requires an immense fixed and working capital investment that can
neither be abandoned nor moved to a new location. At best, existing
infrastructures that is undesirably located (in an economic sense) with
respect to new offshore sources of crude oil will be gradually phased
out by industry as it rebuilds and reorganizes around the newer energy
sources. Therefore, a new OCS field may not be accompanied by a huge
buildup of facilities on the nearest adjacent coast. Contrariwise, one
would expect that platforms would be built at existing yards, that the
crude product would go for processing to present refineries and that
only service facilities would spring up immediately in the local area.

In addition to Texas and Louisiana, there are sizable concentrations
of infrastructure in Southern California and along the east coast in New
York, Pennsylvania, New Jersey, Delaware and Maryland. Infrastructure
is also spread throughout the north central states. For years, the east
coast infrastructure has been supported by oil imported via tankers;
thus it is near existing harbors. Much of this infrastructure was built
to handle imports from the Caribbean Islands.

Refineries in the Caribbean Islands have historically processed
heavy South American crudes (mainly from Venezuela) into residual oils
for the east coast utility (mostly electric power) market. As Venezuelan
oil production has declined, these refineries have turned to eastern
hemisphere crude sources.

It appears that an excess of refining capacity will be available in
the Caribbean for some time. Since the Caribbean Islands lie directly
on the route of tankers from the Persian Gulf, this area has become
highly favored as a refining and transshipment center. Transshipment
seems feasible since oil can be transported to the Caribbean in
supertankers and then moved to the U.S. in shallower draft tankers
capable of directly entering all U.S. ports.

The availability of crude oil to a region is the most critical
factor affecting the establishment and growth of refining capacity. On a
large geographic scale, as crude sources shift, refining capacity will
do likewise, continuing to locate where crude can be made readily
available.

Also, refinery location is dependent on the availability of water
for two reasons. First, location of refineries in proximity to navigable
waterways allows inexpensive transport of oil and products. Second,
large quantities of water are used for cooling in the refining process.

The Gulf Coast region has more refining capacity than any other
region of the United States--41 percent of the total. This compares to

46 percent for the three next largest producing regions combined: the
North, and North Central, Pacific Coast, and Mid Atlantic Coast. The
abundance of refining capacity in the Gulf Coast region is simply the
result of the prolific production of the oil fields of Texas, Louisiana,
and the Gulf of Mexico. The proximity of Gulf Coast refining capacity
to navigable waters, especially deep water, has also given it access to
yet another source of crude foreign imports. For years, Gulf Coast
refineries have received Venezuelan oil and now are increasingly receiving
eastern hemisphere crude.

From the Gulf Coast refining region, large diameter product pipelines
extend throughout the southeast and into the northeast as far as the
Mid Atlantic coastal region. The main pipelines are the Dixie, Plantation,
and Colonial systems.

The refining capacity of the mid-continent region was originally
constructed in response to the oil production of the Oklahoma and eastern
Kansas fields. In recent years, as mid-continent crude production has
declined, its growth has been fueled by crude piped in from the Gulf
Coast region. Future crude supplies will probably come from abroad. It
appears that crude imports will be brought in through the proposed
Seadock "deepwater port" (an offshore anchored transfer station) off
Freeport, Texas, and then move northward through numerous crude pipelines.
Two new crude lines are presently under construction to handle these
probable imports: (1) Seaway Pipeline Company's new 36-inch diameter
pipeline to Gushing, Oklahoma, and (2) the 426-mile 26-inch Texoma line
from Nederland, Texas, to Cushing, Oklahoma.

The refining capacity of the North Central region grew prior to the
1950's in response to oil production in southern Illinois and Indiana,
and in Ohio. This growth has been sustained in recent years by Gulf
Coast crude and by imported crude piped into the region via the Central
American Pipeline system (CAPLINE) and the Mid-Valley system.

The refining capacity of the Mid Atlantic coast has run primarily
on imported oil tankered into the region. Imports have come predominantly
from Venezuela and the Caribbean, but these sources are gradually being
displaced by eastern hemisphere crude predominantly from Nigeria and the
Persian Gulf, and to some extent, from North Africa. Most of this
area's refining capacity is located in the coastal zone , with product
distribution throughout this region and the Northeast handled by small
tankers and barges.

The Mid Atlantic region, despite being the most heavily populated
in the U.S., has only 11 percent of the Nation's refining capacity. A
main reason for this is that the Mid Atlantic receives refined products
via pipelines from the Gulf Coast region and via smaller tankers from
the Caribbean where, in both cases, there are refineries located in
proximity to the oil fields.

The Pacific Coast refining capacity is centered primarily in
Southern California in the Los Angeles-Bakersfield area, adjacent to
major oil fields. Oil processed in these refineries has come from
onshore Southern California fields and offshore in the Santa Barbara
Channel. Today, because California production has stabilized, while
demand has grown, oil is being imported from the Persian Gulf and from
Indonesia. Other Pacific Coast refining centers are in the San Francisco
Bay area and on Puget Sound in Washington state.

A significant future source of crude for the entire Pacific Coast
region, probably beginning in 1977, will be Alaskan oil. This will not,
however, exclude all foreign oil. Plans are proposed to pipe much of
the Alaskan oil east to mid-continent and North Central refineries.

1.1.7 Natural Gas

The first known use of natural gas was in upstate New York in 1821.
Gas for home use was distributed by numerous local gas utilities which
manufactured it from coal. The large steel gas storage tanks still
standing in many major cities are a reminder of that period. However,
in 1947, a major change took place when natural gas from Texas and
Louisiana flowed to the East Coast through two converted liquid pipelines,
the "Big Inch" and the "Little Inch". Since that time, the consumption
of natural gas has mushroomed for residential, industrial, commercial,
and power generation uses. This growth was promoted by several factors
including: the availability of new markets; the replacement of coal by
gas for space heating, for industrial processing, and for the production
of fertilizers and petrochemicals; and the urgent demand for low-sulfur
fuels that occurred in the late 1960's in response to environmental
legislation. Local utility gas mains increased more than four-fold in
the 25 years between 1945 and 1970. The U.S. high-pressure natural gas
transmission network has now been extended into all of the lower 48
states.

1.2 PROBLEMS AND POTENTIALS OF OFFSHORE DEVELOPMENT

National trends in energy demands and petroleum supply have led to
a renewed interest in the offshore for development of oil and gas. In
this section, we discuss the features of the continental shelf and the
geologic potential of offshore areas in general and proposed lease areas
specifically. Resource estimates have been made for each of these
areas, and programs designed for their development. The section concludes
with a detailed discussion of the BLM leasing program currently underway.

1.2.1 The Continental Shelf

The oil and gas industry's prosperity depends upon the recurrent
discovery of hydrocarbons and the continental margins of the world are
prime candidates for their location. The Continental Shelf is a gently
sloping plateau of land that starts at the coastline and runs seaward to
a point where there is a sharply defined drop toward the ocean floor.
Figure 2 depicts the characteristic features of the continental margin,
which includes the continental shelf.

Figure 2. An example profile of the continental
margin (Source: Reference 6).

Land

Ocean

Shelf edge

o.r

Continental
shelf

130 m

- 65 km -

4.3°

Continental
slope

*- 1 5-80 km -

Continental terrace

1 ,400-3,200 m

4,000 m

I
-Continental margin -

Continental rise-

- Deep sea bed

On a global scale, the total continental margin (shelf and rise)
covers more than 20 percent of the world's sea floor and comprises an
area half as large as the total land area of the world (Figure 3). The
total worldwide area of the continental shelf available for petroleum
development is estimated to amount to 1.4 million square miles (3,6
million km ). The width of this shelf varies from one coastal area to
another in the United States. The shelf can be several hundred miles
wide in the Bering Sea off Alaska; in the Gulf of Flexico, it is about
60 miles wide; it extends off the Atlantic coast for approximately 40
miles and narrows to 20 miles or less off the Pacific coast [7].

1.2.2 Exploration and Discovery

The potential of an offshore basin for reserves is estimated by a
sequential process involving geological investigation and geophysical
and seismic surveys. The potential of a frontier area can be approximated
once the following data are known in order of importance: (1) the areal
extent and thickness (volume) of closed oil-bearing geological structures
(Figure 4); (2) the number of such structures; (3) the history of previous
oil or gas production; (4) the geological age of the rocks in the
structure; and (5) the depth to the potential reservoir (oil-bearing)
rocks [3].

An area in a known petroleum producing basin with large closed
structures has a significant potential for hydrocarbons and, if there is
an abundance of these structures, the area will continue to attract
exploration even after some of the structures are drilled and proved
dry. Frontier areas where no previous production has been recorded,
however, may support a significant initial exploratory effort, but if no
reserves are found, interest may decline rapidly. This is because the
investments demanded for geophysical surveys and exploratory drilling
are highly speculative--sometimes they pay off but more often there is
no return.

Once exploratory drilling occurs, the speculative nature of a new
area is rapidly decreased. If paying quantities of oil are found, as
defined by a flow rate test (a "drill stem test") of the exploratory
well, the area's potential will be sharply upgraded in industry's view
and exploratory efforts may accelerate.

If the flow rate test gives uninspiring results, other factors may
still indicate promise for the area. These factors, determined by
sampling cores in the oil-bearing formations, are the rock's porosity and
permeability. If both porosities and permeabilities are high, this
indicates that hydrocarbons can be easily extracted if they are present.

After an exploratory hole has been drilled, it will be possible
to determine whether marketable oil or gas will be found in commercial
amounts. For instance, low viscosity and low sulphur content are more

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(A) arched, (B) faulted, or (C) pierced by shale or salt
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(Source: Reference 8).

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Anticline or dome

level

■■• -i

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sea

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Impermeable layers,
commonly shale

Fi-:-:":-j shale

I : : : : I Sandstone

Salt dome

attractive than high viscosity, high sulphur oil. Oil, if found in a
remote location, is much more easily transported to a market demand
center than gas. (Unless a continuous pipeline can be laid, gas
transport requires conversion to a liquid.) In fact, unless large gas
reserves are found, it may not be economically worthwhile to proceed
with development.

The potential of an area, as defined by these and other factors
(e.g., a scarcity of natural gas or a change in prices) is useful in
forecasting the amount of exploration activity that is likely to occur
in a frontier area.

1.2.3 Geologic Potential of Lease Areas

There are four principal segments of the U.S. Continental Shelf
which are present or potential hydrocarbon provinces. These are the
Atlantic Shelf, the Gulf of Mexico Shelf, the Pacific Shelf, and the
Alaska Shelf. The areas under consideration for leasing on the Atlantic
Shelf include Georges Bank, the Baltimore Canyon, the Southeast Georgia
Embayment and Blake Plateau [9]. (See Figure 5)

Georges Bank is a structural depression in the continental shelf
in the form of a trough aoproximately 190 miles long and 100 miles
wide. The structural deformation consists primarily of high angle
faulting, as illustrated in Figure 4, extending into the basement
crystalline rocks. It is believed that the central and north por-
tions of the basin have the best likelihood of oil and gas accumula-
tions. The water depth, about 250 to 260 feet, and its close proximity
to New England make this area a prime candidate for exploration. A
Continental Offshore Stratigraphic Test (COST hole) which will provide
more detailed information about sediment characteristics was drilled
during the late spring and summer of 1976 off Cape Cod.

The Baltimore Canyon is a trough area which represents a southern
continuation of the Georges Bank geologic characteristics. Geophysical
surveys indicate the possible existence of a wide range of structures
that could trap oil and gas such as faults, reefs, salt domes, and
stratigraphic wedge-outs. Geologists believe that any hydrocarbons to
be found are likely to be natural gas rather than crude oil. In May,
1976 a C.O.S.T. Hole was completed off New Jersey which will provide
further insight into the hydrocarbon potential of the area. The Baltimore
Canyon is considered to be the best prospect on the Atlantic Shelf.

The Southeast Georgia Embayment is a relatively shallow basin that
lies offshore from South Carolina to Florida in water depths up to 600
feet.

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The Blake Plateau is a deeper "trough" that lies about 140 miles
off Georgia and Florida in water depths of between 1,500 feet and 6,000
feet.

The Southeast Georgia Embayment and the Blake Plateau trough are
not as favorably looked upon as potential petroleum provinces as other
areas because of the relatively thin sequence of sediments in the first
case and the deep water conditions in the second.

The Gulf of Mexico is divided into two zones geologically separated
into an eastern province with relatively simple geologic structures and
a western province of complex structures involving faulting and intrusion
of salt beds. Hydrocarbon potential extends from inshore to depths over
1,200 feet.

The Gulf of Mexico has been extensively developed and is the source
of 15 to 20 percent of the Nation's petroleum production. At present,
the known prime areas of the Gulf have been leased, particularly during
the 1970-1975 period. The remaining years of the 1970' s will see less
exploratory drilling and increased development drilling in the Gulf.

The Pacific Continental Shelf includes the following three sectors:
Southern California, central and northern California and Washington-
Oregon DCS sectors. The Southern California PCS is a complex geologic
structure which includes islands, banks, ridges, submarine canyons and
basins. The basins lie in water depths varying between 1,900 feet
and 6,200 feet.

The Central -and Northern California CCS is a region that contains
six structural basins that are extensions of onshore basins. These
basins include from south to north: the Santa Maria, Outer Santa Cruz,
Bodega, Point Arena, and Eel River basins.

Oil has already been produced in the onshore Santa Maria basin (609
million barrels to the end of 1973) and the onshore stratigraphic and
structural trends are anticipated to continue seaward. For similar
reasons, the Eel River basin is believed to be an excellent prospect.

The Washington-Oregon OCS is a region that is part of a trough _
extending from the Cascade Mountains near the coastline to the continental
slope on the west. Although oil and gas seeps and petroliferous muds
have been found onshore near the coast, there has been little production.
However, limited offshore drilling and geophysical surveying suggest that
the offshore presence of suitable sediments exists together with
stratigraphic-structural traps.

Alaska is the northern terminus of the mountain system which
extends in a continuous belt along North and South America (the American
Cordillera). Surrounding Alaska offshore are a number of sedimentary
basins that are potential or proved oil and gas provinces. These basins
lie in southern Alaska, the Bering Sea, Chukchi Sea and Beaufort Sea.

The Southern Alaska PCS is a basin divided into two potential
hydrocarbon provinces, the Gulf of Alaska to the east and the Kodiak to
the west. They are similar in terms of sedimentary sequence, but have
significantly different structural characteristics. Although most holes
drilled in adjacent onshore areas have proven unsuccessful along the
Gulf of Alaska, there was one success in 1902, the Katalla oil field,
which produced about 150,000 barrels of oil before being abandoned.
Moreover, recent seismic surveys have indicated some large scale geologic
structures offshore. One structure is almost as large as the Prudhoe
Bay formation.

North of the Gulf of Alaska-Kodiak Provinces is the Cook Inlet area
consisting of an elongate topographic and structural basin. The offshore
Cook Inlet basin represents a seaward extension of a larger onshore
petroleum province, a portion of which has been explored and is in
production. Through December 1974, the upper Cook Inlet area had
produced 600 million barrels of oil and 1.6 trillion cubic feet of gas.
Discovered but not yet produced reserves are estimated at 500 million
barrels of oil and 4.4 trillion cubic feet of gas [11]. The oil from
upper Cook Inlet supports a small refinery at Kenai, Alaska.

The Bering Sea PCS is a composite of several subregions north of
the Alaska Peninsula arch. Of the sedimentary basins occurring within
or close to the Bering Sea, most promising are Bristol Bay, Norton,
Pribilof, St. George, Zhemchum, and Navarin.

The Chukchi Sea OCS is an area off northwestern Alaska that contains
two depositional areas of interest, the Hope basin--a broad structural
depression in the South Chukchi Sea--and the northern Chukchi Sea
basin--an area underlain by geologic features similar to Prudhoe Bay and
Naval Petroleum Reserve No. 4.

Beaufort Sea OCS extends between Point Barrow and the U.S. /Canadian
border. The Cretaceous rocks beneath the shelf apparently contain
organic-rich shales which may have served as source rocks for the oil
and gas deposits found in the younger rocks onshore.

1,2.4 Offshore Oil and Gas Resources

Shown in Table 4 are estimates of the potential amount of undiscovered
oil and gas resources on the outer continental shelf. These estimates
were recently (1975) prepared by the U.S. Geological Survey after extensive
analysis of existing geological and geophysical data. The figures show
that beyond the Gulf of Mexico and Southern California (which already
possess mature offshore industries), significant hydrocarbon potentials
are found only in the Mid Atlantic (Baltimore Canyon Trough), the North
Atlantic (Georges Bank Trough), and Alaska. The greatest potential is
for Alaska's basins, especially those which are ice-locked most of the
year. High anticipated development costs, though, have so far kept
interest in the ice- locked basins low.

Table 4. Estimates of "Undiscovered Recoverable" Resources, or
Predicted Potential Yields from the Offshore out to Depths of
650 Feet (200 m) [Source: Reference 3)

Undiscovered Recoverable 1

Resourcesl»3

Number on
Figure 5

OCS AREA

Oil
(billion

bbls.)

Gas
(trillion

cu. ft.)

sm2

5%3

Sm2

5%^

No. Atlantic

0.9

2.5

4.4

13.1

Mid. Atlantic

1.8

4.6

5.3

14.2

4-5

So. Atlantic

0.3

1.3

0.7

2.5

Eastern Gulf (MAFLA)

1.0

2.7

1.0

2.8

(0.5

1.3)

(0.3

1.2)

7-8

Cent. Gulf & So. Texas

3.8

6.4

49.0

93.0

(0.9

1.9)

(8.7

19.3)

So. California

1.1

2.1

1.1

2.1

(1.2

2.9)

(1.2

2.9)

Santa Barbara

1.5

3.0

1.7

3.3

(0.9

2.1)

(1.1

2.3)

13-14

No. California

0.4

0.8

0.4

0.8

15-16

Washington-Oregon

0.2

0.7

0.3

1.7

Cook Inlet

1.2

2.4

4.5

17-18

Gulf of Alaska

1.5

4.7

5.8

14.0

Aleutian Shelf

0.1

0.2

0.1

0.5

21-22

Bristol Basin

0.7

2.4

1.6

5.3

23-26

Bering Sea

2.2

7.0

5.7

15.0

Chukchi Sea

6.4

14.5

19.8

38.8

Beaufort Sea

3.3

7.6

8.8

19.3

1. Those economic resources not yet discovered which are estimated
to exist in favorable geologic environments.

2. Statistical Mean between 95% and 5% probabilities.

3. Additional estimates for deeper areas -- 650 to 8,200

feet (200-2,500 m) -- shown in parentheses for four offshore
areas.

The actual amount of recoverable reserves in the offshore frontier
areas is unknown, since no actual drilling has taken place at these
sites. The varying estimates, as shown above, have been based solely on
the interpretation of general geological data. In recent years the
estimates have been consistently revised downward. The 1975 USGS
estimate indicated that the total undiscovered recoverable OCS oil may
be 10 to 49 billion barrels instead of the 65 to 130 billion barrels
estimated in 1974 or the 200 to 400 billion barrels previously estimated
[7].

To determine the rank order of the U.S. offshore areas, the
Department of the Interior, Bureau of Land Manaqement (BLM) solicited
information from all concerned parties [13J. Twenty five U.S. oil
companies responded to the BLM request, identifying 17 major offshore
areas and ranking them based on their view of resource potential
and their order of preference. The 17 areas are listed below in rank
order, with area number (see Figure 5) and projected year of leasing in
parenthesis:

1) Central Gulf of Mexico (7:1976)

2) Gulf of Alaska (Southern Alaska) (17:1976)

3) West Gulf of Mexico (Western Province) (8:1976)

4) Southern California (9:1975)

5) Mid Atlantic (Baltimore Canyon Trough) (2:1976)

6) -East Gulf of Mexico (Eastern Province) (6:1977)

7) North Atlantic (Georges Bank Trough) (1:1977)

8) Bristol Bay (21: not scheduled)

9) Beaufort Sea (28:1978 and 1979)

10) Santa Barbara (part of Central -Northern California) (10:1978)

11) Cook Inlet (Southern Alaska) (20:1977 and 1980)

12) Bering Sea (21-26: not on schedule)

13) South Atlantic (Southeast Georgia Embayment and Blake

Plateau) (4-5:1977, 1978 and 1979)

14) Chukchi Sea (27:1979)

15) Southern Aleutian Shelf (19:not on schedule)

16) Central -Northern California (11-14:1978 and 1980)

17) Oregon-Washington (15-16:1978 and 1980)

1.2.5 Offshore Production Goals and Potentials

In 1974, the President announced plans to accelerate oil and gas
leasing on the Federal Outer Continental Shelf (OCS) on a large scale as
a key part of "Project Independence". Seven million acres were offered
for sale in 1975 and 1.7 million acres actually leased. Sales have been
held for the Southern California, Gulf of Mexico and Mid Atlantic leasing
areas. According to the Bureau of Land Management (BLM) , Department of
the Interior, the goal now is to hold six sales per year (for about 3
million acres per year) through 1980 [7]. The latest OCS planning schedule
(January 1977) is shown in Table 5.

The offshore acreage for sale under the schedule in Table 5 is
shown in Table 6 along with the scheduled date for final sale in each
area. It should be noted that the major constraint on offshore development
is not the time to leasing but the time lag associated with development
of the technological means necessary to exploit the more remote areas.
The acreage of each region that is within the reach of present and near-
term technology is also shown in Table 6. If technical impediments are
overcome in the next 25 years the capability to explore virtually all
U.S. offshore tracts will be available.

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Table 6. Offshore Acreage to be flade Available for Leasing
by the U.S. Bureau of Land Management, According to January
1977 OCS Planning Schedule (Source: Reference 4)

LOCATION

AVAILABLE OCS ACREAGE
(APPROXIMATE)

SCHEDULE DATE OF
FINAL AREA SALE

ACREAGE WITHIN REACH OFTECHNOLOGY

pn:sEr;T

SHORT TEn:^(l!;3[)-1985)

GULF OFMEXICO
(EXCL. FLORIDA)

85 MILLION

9/80

44 MILLION

61 MILLION

FLORIDA MARGIN

95 MILLION

Not on Schedule.

49 MILLION

82 MIL LI or;

ATLANTIC MARGIN

IP'MILLION

3/30

19 MILLION

97 MILLION

PACIFIC MARGIN

51 MILLION

11/80

15MILLI0N

32 MILLION

ALASKA PACIFIC
(EXCL. GULF)

55 MILLION

8/80

36 MILLION

50 MILLION

GULF OF ALASKA

22 MILLION

5/79

16 MILLION

20 MILLION

ALASKA ARTIC

MARGIN

178 MILLION

12/79

6MILLI0N

6 MILLION

8ERINGSEASELF
(EXCL. BRISTOL BAY)

217MILLION

5/80

16MILLI0N

16 MILLION

CRISTOL BAY

35 MILLION

Not on Schedule

10MILLION

16MILLI0N

ALEUTIAN SHELVES

45 MILLION

12/80

3MILLI0N

29 MILLION

TOTAL

890 MILLION

274 MILLION

(31%)

409 MILLION

(«%)

1.3 SCHEDULING OF OFFSHORE DEVELOPMENT

Development of offshore oil and gas is a long and complex process.
This section discusses development scheduling from two standpoints:
first, the six major sequential phases of the development process in
which industry and government are both involved, and second, the time
constraints placed on industry in meeting the most significant scheduling
deadlines.

The ease with which offshore oil and gas fields have been discovered
has been found to be related to the degree of geologic knowledge of the
area involved. More specifically, the knowledge acquired in developing
coastal land hydrocarbon research has accelerated the rate of offshore
discovery. More than 80 percent of offshore fields are believed to be
either offshore extensions of existing onshore or land-based oil pools,
or to have had offshore geology similar to that of the onshore producing
area [6]. Certainly prior geologic knowledge speeds the pace of offshore
oil and gas field development, although other factors are significant,
including technical capability, physical environment, government policies
and availability of investment capital.

1.3.1 Geologic Indications

An offshore extension of a producing onshore field takes on the
average about 4.4 years to discover, while other offshore areas require
approximately fifty percent more time for discovery. Application of our pres-
ent knowledge to the time frame required for discovery and exploitation
of the frontier areas of the United States appears to indicate the
following:

1. Excluding environmental constraints, there is
strong likelihood that certain Alaskan OCS
fields (e.g.. Cook Inlet and Beaufort Sea)
can be developed in a relatively short time
since these areas represent a continuation of
onshore fields and geologic conditions.

2. In other Alaskan areas, a number of other
variables, including the lack of knowledge
of geologic and climatic conditions, could
retard development.

3. However, there are no oil fields on the
Atlantic coast and the thick geologic
sequence of the offshore is not duplicated
onshore; hence, the time frame required for

discovery should be much longer than in
Alaska. (The Atlantic OCS, for this reason,
could be considered unattractive as a
potential oil and/or gas province except for
offsetting favorable conditions of location
and weather.

4. In the intensively explored Gulf of Mexico,
the original development was an extension
of both onshore fields and the geologic
sequence. It has been estimated that
significant production from the deeper
tracts leased in the last three years will
take up to 4 or 5 years.

The decisions on the location, timing and scale of development
described above are translated into activities on the offshore and
facilities on the onshore. Part 2 identifies and describes these
activities and facilities in detail.

1.3.2 Phases of Development

It is convenient to divide the OCS development process into six
major sequential phases. Each phase is characterized by the intro-
duction or development of specific industrial projects and activities.

The six phases are (1) pre-exploration, (2) geological and geo-
physical exploration, (3) exploratory drilling, (4) field development,
(5) production, and (6) shut-in of facilities. The development process
is analyzed by these phases not only because they are physically
different, but also because laws and administrative regulations require
that one precede the next. In a mature petroleum province such as the
Gulf of Mexico, all of these activities may be occurring simultaneously.

A wide variety of activities, equipment, facilities and projects
are required to explore, develop, and place into production oil
and gas fields offshore (see Plate 1, following References, for an
idealized diagrammatic version of the OCS process).

A flow chart of the major activities involved in the exploration
and development of an offshore oil or gas field is shown in Figure 6
along with the six phases of this long and complex process.

1. Pre-exploration: Prior to the initiation of oil and gas
prospecting in a frontier area, significant effort is devoted to care-
fully analyzing available geological and geophysical surveys. The
analyses are done by seismic companies under contract to oil and gas

Figure 6. OCS process chart

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Preliminary Analysis of
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Update Hydrographic Charts
and Shore Control, Tidal
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Resolve Ownership

Regional Geophysical Surveys
Magnetic, Gravity & Seismic
to Locate Sedimentary Basins

Leasing Schedule

Detailed Geophysical Surveys
& Shallow Coring to Locate
I & Detail Structures

Preliminary Site Analysis*
& Preliminary Engineering
Feasibility Studies, Preliminary
Plans for Locating Support
Facilities

Economic Evaluation
LEASE
SALES

Selection of Support Base

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Reservoir Evaluation &
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Detailed Engineering
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Detailed Feasibility Studies
and Selection of Field
Development Program

1) Development Schedule

2) Sizes, Location & Num-
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3) Method of Transport &
Corridor Selection

4) Storage & Treatment
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companies. Such analyses identify sedimentary basins and aid in the
ranking of frontier areas according to their potential for petroleum.

Once it is determined that a frontier area has hydrocarbon potential
it may be necessary, especially in remote areas such as Alaska, to
establish survey control networks onshore and to perform hydrographic
surveys updating navigation charts. Good surveying control and charts
are a prerequisite to reduce the risks to seismic vessels in the search
for offshore oil and gas resources. Increased efforts to establish and
update horizontal control networks, as well as the operation of hydro-
graphic vessels, are therefore a signal of future OCS oil and gas
activities, often followed closely by geophysical vessels searching for
petroleum.

Another aspect of the pre-exploration phase that has often been
troublesome is resolving ownership disputes between the states and the
Federal government. Until the appropriate boundary has been agreed
(outer territorial limit off each state involved) and ownership is
resolved, it is impossible for the industry to obtain development rights
and impossible for the governing body to collect royalties. Often this
will require precise tidal boundary surveys at the shoreline correlated
with tide state data to determine the low tide line, from which 3-mile
(3-league in Texas and Florida Gulf Coast) boundaries can be located.

It is unlikely that the pre-exploration phase would include any
major onshore impacts. Indeed, the public is often indifferent to
exploration activities and other than company employees and involved
Federal workers the only persons who might know that these activities are
occurring are fishermen and other maritime interests.

2. Geological and Geophysical Exploration: This phase, like the
previous phase, does not usually involve major permanent facilities or
major environmental disruption. Work during this phase is based on the
current proposed lease schedule worked out between government and
industry. From industry recommendations developed in the pre-
exploration phase, using regional surveys, the Bureau of Land Management
develops an overall leasing schedule which indicates the order in which
frontier areas will be offered for lease. Once the schedule is set
industry moves its program beyond pre-exploration into detailed geological
and geophysical exploration. The companies individually or collectively
conduct extensive geophysical surveys and shallow rock coring programs
in promising areas to locate and identify geologic structures capable of
trapping and holding hydrocarbons.

Where there are large structures, deep test wells (COST) may be
drilled by a consortium of comnanies "off-structure" (away from where
hydrocarbons collect) to determine the characteristics of reservoir
rocks. The oil and gas companies involved in the effort share the
information gained and the multi -mil lion dollar costs involved.

3. Exploratory Drilling: Significant facilities development
projects first occur during the exploratory phase. Exploratory drilling
activity requires the development of shore support industries, service
bases, and marine repair and maintenance facilities. More important,
the ground work for other major projects is made during this phase,
including obtaining land options and acquiring necessary permits and
approvals. Oil and gas companies initiate strategies during this phase
that emphasize minimal capital investment.

Exploratory drilling is an operation that begins with relative
uncertainty of success, especially in a new province where geologic data
are incomplete. Each additional exploratory well drilled and each rock
core examined rapidly increases the information base and allows better
placement of the next hole.

Teams of geologists carefully examine the records of the seismic,
gravity, and magnetic surveys to determine a promising location for the
first exploratory well. As drilling proceeds, rock cores are removed
and periodically the well is "logged". Well logging is a process by
which sonic, electric, and radiation characteristics of the sub-surface
rocks are measured, in place, for mapping sub-surface structures.

If the first exploratory well hits what seems to be a commercial
find--that is, an encouraging rate of flow of oil or gas--another well
will be drilled nearby to confirm the discovery. Success here means a
new field has been found and efforts are immediately devoted to estimating
the size of the find. A more accurate estimate is developed as appraisal
("step-out") wells are drilled to delineate the horizontal extent of the
field and determine the number of wells needed to economically drain the
field.

Using the rock cores, well logs, and drill stem tests taken during
the exploratory drilling program, petroleum production engineers evaluate
the reservoirs to determine the best areas in which to set up permanent
oil or gas recovery wells and establish production platforms.
Simultaneously surface site investigations are initiated to determine
foundation characteristics and subsurface geology of the potential
platform locations. Platform locations, then, are determined by the
combined efforts of reservoir engineers and engineers who are responsible
for designing, fabricating, and installing the platform.

4. Field Development: Field development embraces the rapid
implementation of strategies developed during exploratory drilling and
earlier phases. (Detailed descriptions of field development and production
are discussed in Part 2). During field development, company strategies
are refined and reoriented as new and detailed information on the resource
comes forth. This reorientation may be expressed in changes in location

of onshore supporting facilities. During this phase, the pattern of
development becomes crystalized, and it is unlikely to change significantly
throughout the productive life of the field.

Field development entails the establishment of a number of major
onshore and inshore projects. Possible new projects include fabrication
yards, pipelines, natural gas processing plants, pipe-coating yards,
transfer systems and onshore storage facilities. Additional onshore
support facility development will also be stimulated. The particular
pattern of component projects will relate to the resource characteristics
and location.

A large find located far from established existing facilities--for
example, Prudhoe Bay in Alaska--will stimulate the greatest development
"boom". Conversely, a small oil field developed off Georgia would
likely utilize products and services transported in from the Gulf of
Mexico coast. Refineries in the Caribbean also could be utilized in
lieu of refineries in the United States. The ratio of gas to oil in the
deposit, and the location of the resource, in relation to existing
transportation and processing facilities will also affect the decision
as to whether to engage in nearby facilities development.

5. Production: The production phase involves a continuing though
lower level of activity but little new strategy. The industrial infra-
structure becomes more complex and "mature" during this phase. Production
will overlap with exploration for after the initial platform comes on
line, exploratory drilling continues in other portions of the basin.
Field production patterns are closely intertwined with lease patterns; a
large number of companies leasing a field may lead to more production
platforms, while if a single company leased an entire field, in theory,
only one platform might be required.

The production phase will likely encompass 20 to 30 years. The
length of time relates to the size of the field and rate of recovery. In
addition, industry is constantly searching for techniques to capture a
higher percentage of reservoir hydrocarbons from producing fields. If
these efforts are successful, then the life of the field may be
expanded--often through "working over" an existing field by applying new
or different approaches.

6. Shutdown: As the oil and gas of the specific offshore field
approaches exhaustion, it is necessary to start decommissioning specific
facilities and installations, i.e., the removing of production platforms.
(Only those offshore structures which have been damaged or destroyed by
storms have been removed from the Gulf of Mexico.) Refineries would
undoubtedly remain but would now have to rely on new sources of supply
piped or shipped to the area.

The U.S. Geological Survey normally requires that when a platform
is dismantled, all casing or piling is to be cut 15 feet below the sea
floor and removed. The well site is then to be dragged to assure removal
of any possible obstructions.

Pipelines are generally left in place since the cost of removal is

more than the salvage value of the pipe. However, the connection between
the line and the platform is cut at the base of the riser after which
the line is capped and sealed.

Tank farms erected for receiving OCS crude oil can obviously be
used for storage of oil from other sources but it is more likely that
they will be scrapped. Natural gas processing plants would be salvaged
or possibly converted to another use.

1.3.3 Time Constraints

Like any business, the oil and gas industry operates for profit.
Its schedules, along with other operating strategies, are consistent
with optimizing that profit. OCS development activity follows a
sequential process in which success during one phase will determine if
the next phase should be either initiated, delayed or cancelled. The
whole process is very complex and risky.

The time frame for bringing an offshore oil or gas field into
production from the time of initiation is conditioned by three principal
influences:

1. Geologic factors - involving acquisition of knowledge on

the nature of the geologic structure and lithology underlying
the area which in turn determines the pace of discovery and
the production parameters.

2. Economic criteria - encompassing the myriad of marketing,
managing, organization, capital availability and other
problems facing an industrial firm considering offshore
hydrocarbon development.

3. Regulatory processes and constraints - including all of
the Federal and State (and local) reports, operating
orders, rules, regulations, standards, and procedures
that need to be followed and observed in all phases of
offshore operations.

It may take as much as ten years from the time an entrepreneur
decides to embark upon an offshore venture to the commencement of
production. Even after initial discovery, there will be a protracted
period in which appraisal wells are drilled to define the size of the
field, productive geologic horizons, outer geographic boundaries, and
recoverable reserves. The information derived from appraisal wells is
utilized in determining the field development requirements, such as the
number of production platforms, the number and location of production
wells to be drilled, the size and number of oil tankers or the size and
location of pipelines, and the capacity of onshore receiving terminals.

Forty-six examples are given of financial, planning, organizational,
management, engineering and general business problems to be overcome--
the large capital outlays committing industry to a specific course are
concentrated in the latter stages of the schedule as shown below [13]:

Elapsed Time Activity

(years)

0 1. Establishment of initial organization

2. Determination of purpose

3. Determination of structural approach

of business entity (sole risk or
joint venture)

4. Formation of business entity (corporation,

partnership, etc.)

0.5 5. Establishment of requirements (final

needs and budget)

6. Creation of plan

7. Evaluation of means (to gain competitive

position)

8. Estimation of costs and timing

9. Framing of objectives

10. Study of preliminary tasks (economic

analysis, infrastructure required,
and markets)

11. Determination of equity positions

12. Finalization of decisions

1.25 13. Start of negotiations for lease or

concession

14. Contracting of seismic survey (and

study of regional geology)

15. Geophysical surveying of area

16. On-site seismic surveying of area

17. Detailed seismic surveying of anomalies

18. Evaluation of seismic data

2.6 19. Submission of offer for leases

20. Negotiation of terms

21. (In foreign country, registration of

business entity)

22. Selection of base of operations

23. Updating of economic studies

3.7 24. Determination and elimination of roadblocks

25. Start-up of research

26. Acquiring, equipping, and staffing of

operating base

27. Installation of communications system

28. Determination of number of exploratory

wells to be drilled

4.6 29. Selection and negotiation with drilling

contractor and determination of type of
rig required

30. Arranging for other services needed for

exploratory drilling (support craft,
helicopter services, and
all types of supplies)

31 . Drilling of wells

32. Analysis of drilling results to assess

need for additional seismic surveys

33. Review of geological data and estimating

of reserves

34. Drilling of confirming or appraisal wells

35. Securing of soil and sea bottom samples

36. Obtaining of oceanographic data

5.1 37. Completion of Exploratory phase

(go:no-go decision on field development)

38. Establishment of firm plans and

commitments (determination of equip-
ment requirements, platform types,
storage and transport systems, reserves,
probable production schedule, optimum
well program, government regulations,
and additional financial needs)

39. Estimation of equipment with long

delivery dates

40. Establishment of development drilling

program

41. Expansion of staff

42. Selection of engineering and construct-

ion firms for design and fabrication
of platforms, pipelines, terminals,
and other systems and facilities

6.5 43. Design of process system, pipeline,

support system, and loading and
unloading terminals

44. Installation of platforms, pipelines,
and terminals

9.5 45. Installation of drilling systems and

drilling and completion of production
wells

10.5 46. Commencement of production

PART 2 OCS DEVELOPMENT SYSTEMS
INTRODUCTION AND GUIDE

This part of the report is intended as both an introduction to the
specific activities and facilities involved in development and a reference
document for the impact assessment which is the ultimate effort of
the OCS project. Sections to follow discuss the various aspects of
offshor and related onshore technologies that industry may employ in
OCS dev opment--techniques currently in use in the United States and
those un !er development.

Offshore oil and gas recovery ventures are financed principally by
private industry. The U.S. government both regulates and provides
various measures of assistance. Offshore activities are initiated by
the OCS industry with geophysical surveys supported by geological
studies designed to locate structures and formations that may contain
oil and gas deposits. If industry and the Federal government agree that
an area has geologic potential, the government may hold a sale and the
companies successful in bidding may undertake exploratory drilling to
determine the recoverable hydrocarbon reserves.

If sufficient reserves are discovered by exploratory drilling, the
operators will embark upon a program of field development to initiate
production. A development program will involve not only the drilling of
producing wells, but also the installation of platforms, separators to
process crude oil and gas offshore, pipelines or vessels to transfer the
oil and gas onshore, and onshore tank farms and plants for additional
processing. During the production period, additional wells will be
drilled, existing wells will be serviced to maintain production, and a
variety of techniques will be employed to stimulate lagging output. The
oil and gas produced are shipped by pipeline and/or vessels to onshore
facilities for refining and marketing.

An understanding of the entire offshore development process is
necessary if one is to understand the full range of services, materials,
and facilities needed to support offshore activities. The impact of OCS
oil and gas activities will fall most heavily upon those onshore
communities which become the principal staging areas for offshore
operations, and which may become the site of energy transfer and
processing facilities. The spectre of these impacts, whether real or
imaginary, appears to have become the focus of OCS-related debate in
coastal communities adjacent to proposed frontier areas. Officials at
the local, county, and state levels are often unsure what effects,
positive and negative, they should anticipate. Little information on
environmental or economic effects has been available to ease or confirm
their concerns.

Organization: Part 2 contains three sections of general discussion
followed by a description of 15 specific OCS projects. This general
discussion is intended to complement the information on technical
aspects of OCS development presented previously in Part 1 by providing
information on (1) community acceptance, (2) environmental constraints,
and (3) regulatory aspects.

The 15 most significant projects have been selected for detailed
description with emphasis on the strategies of OCS development. The
decision systems of oil companies and related firms which govern OCS oil
and gas recovery must be examined in relation to the six phases of
offshore development previously discussed. Each phase is associated
with specific offshore activities and needs and with selected onshore support.

The fifteen projects are as follows:

Offshore Development Projects

1. Geophysical survey

2. Exploratory drilling

3. Production drilling

4. Pipelines

5. Offshore mooring and tanker operations

Onshore Development Projects

6. Service bases

7. Marine repair and maintenance

8. General shore support

9. Platform fabrication yards

10. Pipe coating yards

11. Oil storage terminals

Processing Projects

12. Refineries

13. Petrochemical industries

14. Gas processing

15. Liquefied natural gas processing

This choice of projects was made after analysis of known facts
about effects of oil and gas recovery on living resources. While
concerns about offshore petroleum development have traditionally focused
on offshore aspects, the choices above reflect an emphasis on onshore
facilities.

The offshore activity and onshore facility projects begin operation
at different times in the OCS and related onshore development process as

shown in Figure 7. The chart illustrates the operation life of each
process and includes some gradation for times when operations may
continue or will continue at a lower scale. This chart illustrates that
most planning for facility projects will occur during the last exploratory
drilling and early field development phases, after basic characteristics
of the field are known and exploitation and support requirements are
defined. As shown, each facility follows a sequence which could be
clearly observed in frontier areas. These distinct activities will be
unrecognizable in an area with established production as the various
activities overlap.

Following an introduction, each of the 15 project descriptions
presented in Sections 2.2 - 2.4 is divided into 8 standard units:

1. Description

2. Site requirements

3. Construction/Installation

4. Operations

5. Community Effects

6. Effects on Living Resources

7. Regulatory Factors

8. Development Strategy

Introduction: The introduction to each section relates the project
to other projects, presents the current situation nationally on the type
of projects, and includes a project implementation schedule, or timeline,
to show the minimum feasible time from initiation to completion of a
project. The time scale is presented as a minimum because average
time could be affected by numerous and unpredictable delays along
the scale. The schedule is generalized to illustrate major elements of
the process; it is recognized that a sponsor may complete hundreds of
distinct actions to complete a single element.

The contents of each unit are briefly reviewed below:

(1) Description: Presents the project and its components in a
narrative and graphic format. When finished with a description, a
reader should have a clear image of the physical attributes and processes
associated with the project.

(2) Site Requirements: Site requirements include important
locational considerations. Factors such as waterfront location, access
to navigation channel, and access to other transportation elements are
important strategic considerations for many of these projects. Where
possible, the relative weights of various factors are discussed, as some
requirements must be met while others are merely desirable.

(3) Construction/Installation: An important aspect of several
projects, such as platform fabrication yards, relates to construction
and installation. These concerns are emphasized in this discussion

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where construction itself, rather than location, design, or operation
has the major potential for impact.

(4) Operations: For a number of the projects, such as onshore
support and drilling operations, operation factors--method, duration,
and scope--may be more significant than construction and installation.

(5) Community Effects: This topic addresses induced effects of
OCS development. A key factor in assessing community effects is
employment. Estimates of demands for services, facilities, housing,
etc., can be projected from a combination of the increased employment
figure, and the project's onsite demands. From these results, estimates
can be made of effects on living resources.

(6) Effects on Living Resources: Important environmental strategies
related to resource conservation and environmental concerns, especially

as they affect living resources--particularly fish and wildlife and
their habitats--are discussed (environmental concerns in which the Fish
and Wildlife Service is not involved are de-emphasized). As appropriate,
conservation-environmental discussions are segmented into four distinct
phases of project development: location, design, construction, and
operation (including maintenance).

(7) Regulatory Factors: Federal, state, and local regulatory
concerns are segmented and described. Discussion of state and local
concerns, which vary greatly, is generic. Discussion of Federal
regulations is specific and relates back to information in previous
sections, primarily the description, site requirements, and environmental
factors. The strategy of the sponsor is discussed in terms of avoidable
and unavoidable requirements. Strategies to minimize procedural delays
are emphasized.

(8) Development Strategy: This section relates the other elements
of the presentation to each other. Major strategic considerations are
compared and contrasted from the perspective of a decisionmaker in OCS
development. The purpose is to enable the reader to understand which
constraints are most important and the logic behind the tradeoffs.

The six major elements, or steps, common to planning and construction
aspects of OCS projects are shown on the timeline example chart (Figure
8). An important fact is that variations can occur in the permit sequence,
but the other three steps— site option, site purchase, and construction--
invariably occur in that order.

The first step is obtaining an option on a potential site. After
the option is obtained, use and location permits are sought, primarily
through local units of government. These permits may include zoning
changes, planning commission approvals, and special use approvals. In
addition, certain projects may also require approvals at the state
level .

At the completion of this phase, the sponsor has local approval to
proceed with his concept and can purchase the property. After the
property is purchased, a series of preconstruction permits must be
obtained; these incorporate most of the major Federal requirements such
as environmental impact statements and dredge and fill permits in
selected cases.

After the permits are obtained, construction is initiated. During
the construction phase, operating permits that may not have been obtained
earlier, are sought; however, any permits that are considered difficult
to obtain are likely to have been sought prior to construction while the
investment was still minimal. After construction is completed the
facility can then begin functioning in the OCS oil and gas process.

Figure 8. Project implementation schedule (sample).

INVESTMENT COMMITMENTS:

Site Purchase
Site Option(s) Taken

Start of
Construction

YEARS •••

PERMIT ACQUISITIONS:

Begin
O Project
Operations

Acquisition of Use and
Location Permits

Operating Permits

Preconstruction Permits
(Includes EIS)

2.1 FACTORS OF INFLUENCE

In the implementation of an OCS development system there are a
number of important spheres of interest. In this section we discuss
four of these. The first three--community (indirect) effects, living
resources, and regulatory factors--are to be covered in detail in separate
reports of the OCS project series (Volumes 2, 3 and 4). They are covered
here only to the extent necessary to provide a background for the
descriptions of specific OCS projects. The section concludes with a
discussion of industry decision factors.

2.1.1 Community Factors-- Indirect Effects

The key factor in assessing community effects is employment. The
total number of individuals to be employed is the summation of direct
employment (the facility project under consideration), indirect employment
(working for other companies that support the facility project), and
induced employment (employment generated in other sectors of the economy
such as school teachers). (Indirect and induced employment are addressed
in detail in Volume 3 on community effects.)

Critical matters to consider in employment are: (1) the different
requirements of construction and operation employment, (2) the interrelated
timing of employment opportunities for individual projects, and (3) the
percentage of employees who are new regional residents. For many projects,
such as refineries and pipelines, construction and installation require
large labor forces, while operating employment is much lower. For other
facilities, such as platform fabrication yards, the operating force may
exceed the construction labor force.

During construction and operation, a percentage of employees will
also be new residents to the area. Those who are current residents will
not require substantial changes in local services, while new residents
will require service from the public and private sectors that had not
been demanded previously. The number of secondary and induced employees
needed because of the new direct employment is difficult to predict. A
number of factors affect the relationship to direct employment; the size
of the community before the project, income of workers, length of
construction phase, and distance from metropolitan areas are the most
important. As a general rule, from 0.3 to 0.9 secondary workers are
needed for each new construction worker, and from 1.1 to 2.3 secondary
workers for each permanent employee [6], while induced employment on
OCS-related industry is projected to be at least 1.2 for all direct and
indirect workers.

Induced effects are a major consideration. Communities concerned
with industrial development options tend to view new plant payrolls and
property taxes as an added economic benefit, and local commercial
interests sense the potential for increased profits. But the commitment
of coastal lands for heavy industry sites may engender a wide variety of
impacts that extend considerably beyond the direct, localized, impacts
of the plant. Certainly, new residents employed by a new OCS facility
will generate a demand that may require expansion in the public sector
for utilities and services such as sewage treatment and water supply,
and may induce housing projects, shopping centers and other community
development in the private sector. And the facility may attract more
industry. All this development has a potential for impact on living re-
sources. In addition, costs to the community for more streets, police and
fire protection, schools and other essential services, may be greater than
the direct costs of the plant itself, requiring that planning decisions
relating to industrial siting must include the development they will
induce.

2,1.2 Effects on Living Resources

Resource conservation and environmental impacts may be severe for
onshore facilities. Those concerns relating to fish and wildlife and
their habitats are most significant for large, heavy impact OCS
projects, i.e., exploration and production drilling, platform fabrication
yards, pipelines, oil refineries, and petrochemical industries. Effects
on living resources may arise from decisions made in each of four distinct
phases of OCS projects: location, design, construction, and operation
(including maintenance). The following considers only those factors
having a major influence on fish and wildlife and excludes marginal
factors of importance to them even though they may be important otherwise
(e.g. , air pollution).

Location: Waterfront locations of facilities may require dredge
and spoil disposal which can lead to adverse ecologic effects, such as:
(1) turbidity; (2) eutrophication; (3) toxification; (4) basin shoaling
and oxygen depletion; (5) wetlands loss; and (6) benthic habitat
degradation. Other major consequences of the waterfront location include:
(1) shoreline alteration from bulkheading; (2) preemption of land for
filling; (3) disruption and degradation of wetlands and other vital
areas. Solutions can be effected through taking special care to reduce
effects on terrestrial wildlife, endangered species habitats, and aquatic
ecosystems. Where waterfront locations are not required for the facilities
the use of upland areas will preclude many of these problems and will
retain waterfront sites for uses which require that type of access.

Design: The high potential for adverse aquatic impacts of the
waterfront location requires that maximum care be taken in design of the
facility. Solutions include provisions for: (1) maintaining the natural
shoreline; (2) minimizing dredging; (3) arranging proper disposal of

spoil; (4) avoiding wetlands; (5) reducing problems of runoff discharge
through proper watershed management and (6) provision of buffer strips.

Facilities handling petroleum will cause concern for: (1)
avoidance of oil spills; (2) avoidance of discharge of pollutants and
(3) minimizing subsurface water withdrawal. Also the large acreages of
shorelands require that special care be given to reducing effects on
terrestrial wildlife, endangered species habitats, and the aquatic
ecosystem. Elevations below the 100-year flood level are undesirable for
OCS facilities in coastal or floodplain areas.

Construction: During site preparation there can be a number of
serious effects, direct and indirect. Solutions can be found through
(1) minimizing the alteration of water systems; (2) preventing the
erosion of soil; and (3) eliminating the discharge of toxic or deleterious
substances. Excavation and filling of areas near wetlands must be done
in such a manner that sediments do not enter the wetlands ecosystems.
Revegetation of disturbed areas must be accomplished as soon as possible
to reduce erosion.

Operation: The major environmental problem of OCS projects in
operation generally will be in meeting pollutant discharge standards on
waste disposal and runoff water. Solutions are through proper application
of Federal and state pollution controls. Frequent maintenance dredging
of an access channel may cause serious problems, particularly in the
availability of suitable disposal sites for spoil. Therefore, location
and design standards are important. Spill containment precautions
should be developed.

Sponsor Strategy: Normally, the sponsor's environmental concerns
are related to the governmental regulatory controls that must be met and
to public reaction to environmental and other impacts. Extensive
administrative and litigative delays can result if either environmental
assessment studies are weak or if the mitigation plan is inadequate.

Normally, location problems of the facility are by far the most
important ones affecting fish and wildlife resources, and the one that
the sponsor will give the most effort to solving. Next in order will be
designing the facility to avoid shoreline disturbances, particularly of
wetlands. Third and fourth in priority will be requirements for construction
and operation. However, depending upon the locale and other specifics,
the priority of the above may change dramatically. In any event, concern
for the fish and wildlife resource is only one constraint in the whole
development sphere and often there are strong pressures to subjugate
such concern to economic and social factors or to other environmental
aspects (e.g., air quality, scenic impacts).

2.1.3 Regulatory Factors

Onshore projects and facilities for offshore oil and gas development
must meet location, design, and operating conditions imposed under a
broad array of state, local, and Federal laws and regulations. The Fish
and Wildlife Service participates in two distinct Federal program areas
with implications for OCS-related onshore facilities: (1) general,
under a variety of Federal laws applying to onshore and nearshore develop-
ment; and, (2) specific, under the Outer Continental Shelf Land Act and
the lease tract selection, evaluation, and management process authorized.
(Table 7)

First, through the Fish and Wildlife Coordination Act, the Service
is advisory to other Federal agencies in direct regulation or management
of certain development activities onshore and in the nearshore area.*
In this first subject area, the Federal regulatory role as it affects
privately owned land is concurrent with state and local programs, often
in the same subject areas.

Second, in the Outer Continental Shelf leasing program the Service
contributes in suggesting or reviewing stipulations for lease sales
which include conditions for offshore development. Because leasing
involves the sale of Federal interests to private parties in an area of
exclusive Federal jurisdiction, the Bureau of Land Management (BLM)
prepares final decisions on leasing and the Geological Survey (USGS)
takes similar actions for exploration, development, and production
management.

Fish and Wildlife Coordination Act, 16 U.S.C. 661-667e; 48 Stat.
401, as amended; and the related provisions of the National
Environmental Policy Act of 1969, 42 U.S.C. 4321-4347.

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In addition to these two primary categories. Federal highway programs
and most pipeline decisions also involve the FWS in an advisory role.
Under the Coordination Act, the Service may, upon request, provide
advice to states in certain situations where their development activities
require Federal permits or certifications.

Site locations in nearshore and onshore areas are significantly
affected by state and local laws and regulations. The interaction of
land and water requirements for a site, and the size of the site used
for storage and industrial activity govern the extent of applications
to state and local governments for zoning and related permits. Permits
or approvals required before starting construction typically include
one or more of the following:

• zoning use designation

t permission to subdivide land ownership
t certification of flood proofing and location
outside highest flood hazard area

• wetlands or critical areas conservation or

impact mitigation

• site alteration assurances to guard against

erosion or drainage alterations

• dredge and fill permit (state)

This report will not discuss these programs, but excellent secondary
sources exist. [Note: For example: HUD, Statutory Land Use Control
Enabling Authority in the Fifty States, September 1976, U.S. GPO/HUD-
FIA-179. J Permission under many of these types of regulations may be
denied as a matter of state (or local) policy at any point in a sponsor's
planning process before construction begins. Because of this, local
assurances such as zoning approval are often sought well before
applications for Federal permits are submitted.

In addition to development-related permits, operation of a facility
may require both Federal and state permits. The most common categories
include pollutant discharge and maintenance dredging.

An important consideration in the formal regulatory process is
coordination of state and Federal programs. Corps of Engineers'
regulations require state disposition of related issues before issuance
of Corps dredge and fill permits. [Note: Regulations published July
25, 1975, Volume 40 of the Federal Register, pages 31320 et seq.]

The Coastal Zone Management Act of 1972 requires greater coordination
between state and Federal agencies in states which have approved Coastal
Zone Management plans.

Faced with the economic risks and the complexity of the regulatory
process and equally demanding capital financing requirements, a facility

sponsor must make several crucial decisions in attempting to locate an
onshore OCS-related development facility. Subtle issues in the regulatory
enforcement process may affect the short and long-term potential a site
has for the sponsor's needs. For instance, the existence of a state
"large-scale-development" review program may cause delays in initial
site approvals, but may provide greater security than simple local
zoning approvals to the life of a development. Location in an existing
industrial area may eliminate many local approvals because zoning would
already permit industry. But land prices for the site may be higher
because of the greater simplicity or attractiveness of the site. The
decision becomes primarily one of capital availability and carrying
costs (primarily interest on borrowed money) rather than site character-
istics.

Information requirements for different public approval programs may
differ significantly. Sequential presentations with each specifically
tailored to one agency to get one approval have often been more effective
than blanket or overview reports that might arouse general interest in
the details of a project. The environmental impact assessment process
has changed traditional approaches to this problem, as described in
Volumes 2, 3, and 4 in this series, each of which deals extensively with
the sorts of information commonly presented and with important concepts,
definitions, and ecologic factors that come up in either the tailored or
general information approach.

Pre- leasing and exploratory drilling reviews typically proceed
independently of sponsor attempts to locate suitable onshore sites for
related development. During the field development phase, onshore
facilities are also being sited with applications to the Corps of
Engineers, who are advised by district and regional representatives of
FWS.

2.1.4 Industry Decision Factors

The offshore industry's decision process is aimed at finding the
optimum balance among a complex set of tradeoffs. The tradeoff elements
include technical, environmental, regulatory, community, and direct
economic factors. This section focuses on the principal factors that
affect the whole OCS development decision process.

Economic Constraints: Profits from OCS development depend on the
costs of recovery, which are a function of the difficulties of exploration
and development, which in turn, are dependent upon both the location of
the frontier area and the technical difficulties of operating the area
in which drilling is planned.

If the potential for payoff is doubtful and a company's rate of
profit is unfavorable, it is extremely risky for the company to engage
heavily in exploration activities. If a marginally commercial discovery

is made, the company might have a problem generating capital to develop
the field, as well as the considerable tine lags before the field
would be on-line generating an incoming cash flow. In a remote and
hostile area, such as Alaska, the huge front-end investment costs and
the estimated 5 to 8 year span between discovery and production may
exclude all but the largest and most wealthy of oil companies--and they
create joint ventures to spread the costs and risks in major
development.

To assess the risk of investing in offshore oil resources from an
industry point of view, the following major factors need to be
considered:

1. the physical costs of installing and operating producing
wells and facilities for various water depths and climatic
conditions;

2. the cost of exploratory dry holes (up to $1 million each)
that must be paid for by production from successful
wells;

3. nonphysical costs such as royalties, taxes, bonuses, and
the cost of capital including required return on
investments;

4. size of the oil/gas field, physical characteristics and
productive capacities for a single producing facility;

5. the timing of technical capability for operating at various
water depths and climatic conditions, assuming that the
current state of the art precludes operations under ice
conditions or in depths in excess of 3,300 feet (1,000 m);

6. estimated costs of other fuels with which offshore
petroleum must compete;

7. marketing costs and considerations (e.g., need to
maintain market leadership in a given area).

Offshore oil development can be economical under a wide range of
reservoir size, water depth, and climate conditions. Economic feasibility
rapidly diminishes as reservoirs become smaller, water deeper and climatic
conditions more severe. It must be realized that the petroleum industry
does not profit from exploring for oil; its profits come from
production and marketing. Geological and geophysical surveys and
exploratory drilling operations, though necessary to assure the industry's
long-term survival, are regarded as speculative ventures by the industry.
When industry's profits fall, exploration expenditures are curtailed and
emphasis is placed on developing already discovered reserves. This

represents a more conservative investment, since the economic and technical
feasibility of developing known reserves can be fairly accurately
determined, and only those projects yielding an acceptable rate of
return will be initiated.

The decision to proceed or not to proceed with offshore exploration
and development of OCS oil and gas is an investment decision based on a
company's estimate of the costs involved in relation to the revenue
generated and the ultimate return on investment. Operations offshore
are considerably more expensive than onshore and the investment risk and
the return must be higher than what usually has been considered adequate
for onshore operations.

The massive capital cost associated with establishing an offshore
production field weighs heavily upon the decision to proceed with OCS
development. As operations have moved into deeper waters, more hostile
environments, and more remote areas, the capital cost of the facilities
required to bring a field into production have climbed into the hundreds
of millions of dollars. Development of Phillips Petroleum's Ekofisk
field in the North Sea has cost approximately $4.5 billion. As a result
of such high costs, British operators now estimate that fields in the
North Sea must yield at least 200,000 barrels of oil per day to be
economically feasible. Support of the heavy "front-end" capital
investments required in frontier areas, especially the remote areas of
Alaska, will require production in excess of 100,000 barrels per day.

Other important financial factors considered by the industry are
the cost of money, i.e., the prevailing interest rate to corporate
borrowers, and the considerable time involved between investment and
production. Time lags are in actuality money costs, because the investor
foregoes the opportunity of gaining a return while his money is tied up
in non-productive investment. When the time lag between beginning the
development of an offshore field and initiating production is long, as
it will be in the more remote areas of Alaska, only fields with
substantial reserves will attract investors.

The overall investment of capital for developing offshore resources
both here and abroad is anticipated to continue at a rather vigorous
pace in the next few years. One estimate, predicts that in the years
1975-1980, expenditures for exploration in North America will amount to
$15 billion (85 percent of which will be in the United States), while
development costs to produce the discovered oil and gas fields will
amount to over $21 billion [14].

A most troublesome economic factor for the U.S. oil and gas industry
in the last several years has been inflation. The industry has had
problems getting a reliable prediction of what a project will cost when
finally completed. Costs on many projects have escalated drastically
from inception to final completion in the 1970' s.

The costs of exploratory and development/production drilling and
other services incidental to offshore exploitation have risen particularly
steeply. For example, a jackup rig which cost $8-9 million in 1971,
cost close to $20 million by 1976.

Market trends are very important. The current and future price of
oil and gas, their demand outlook, and the cost and availability of
petroleum from alternative sources all have significant influence on the
decision to proceed with development. During the past few years, the
above factors have become somewhat unpredictable due to the instabilities
in the world market. For example, since Middle East production costs
are a fraction of the U.S. production costs offshore, these nations have
a great deal of flexibility in manipulating the market, such as increasing
production and simultaneously lowering oil prices, which could undermine
investment in U.S. offshore development.

The location of a promising field, and the distance to the desired
market is important. If oil and gas are discovered in a frontier area,
they must be transported to a refining center to be nrocessed and readied
for distribution. A field in close proximity to a refining center will
probably require a much lower threshold of reserves to make development
economically feasible. Oil can be transported by tanker from remote
areas, but the threshold of reserves required to encourage an investment
for the construction of oil storage and transfer systems or a pipeline
to shore may be quite large.

Technical Constraints: The difficulty of recovery of oil and gas
resources is a function of the hardship and complexity of exploration
and development. This in turn depends upon both the location of the
frontier area in which drilling is planned and its characteristics.

A major factor which affects the cost of exploration and feasibility
of development of the frontier area is the degree of remoteness from
sources of supply for steel, pipe, concrete, platform jackets, and other
heavy industrial goods. All of the Alaskan frontier areas are remote
from the source of supplies, especially those basins north of the
Aleutians. Here, transportation costs add significantly to the cost of
development. In contrast, the U.S. Atlantic frontier areas are all
relatively near supply areas.

Another important locational constraint affecting the difficulty of
developing an offshore field is the distance between the offshore oil or
gas field and the shore. The cost of transporting men, fuel, materials,
and drilling equipment is a function of distance travelled. In storm-
swept areas such as the Gulf of Alaska, Bristol Bay, and the
Bering Sea, distance is especially critical, because of weather changes
during the long trip; for example a supply vessel can depart in good
weather but encounter adverse conditions before reaching the platform
and off-loading. Supply may be impossible for many days while costly
drilling rigs or platforms stand idle.

Depending on the severity of conditions--wind, waves, currents,
tides, storms, earthquakes, temperatures, and ice--the cost of offshore
development can escalate to almost five times the cost incurred under
ideal conditions (few storms, light winds, mild tides, no ice) as found
in the Persian Gulf and Mediterranean Sea. Ice imposes the most severe
limitations, and thus the greatest increase in cost. Transport through
sea ice is nearly impossible; the shearing and crushing effects of sheet
ice on fixed structures impose severe design criteria on platforms; and
it may be nearly impossible to construct a pipeline to shore that will
not be ruptured by moving ice floe pressure ridges.

A third factor affecting development is the geological character of
the ocean bottom which must support the production platform. Areas of
difficulty are soft sediments, mud slumps, sand waves, rock outcrops,
steep slopes, and faults. If technical solutions are not available,
development is precluded on such OCS areas.

A fourth factor is water depth. The difficulty of either exploration
or production is compounded by deep water. This is reflected in the
complexity of drill rigs required for deeper water (semi-submersibles)
as opposed to those required for shallower (less than 350 feet) waters
(jack-up rigs). Development costs are as heavily dependent upon water
depth as exploration costs or more so. For example, standard platforms
("fixed" type) increase in cost as a function of the square of water
depth. In order to maintain a stable base-to-height ratio in deeper
waters, platforms increase exponentially in size and in number of joints.
Therefore, the amount of material and labor required also increases
exponentially.

Table 8A compares drilling expenses for a base case of the Gulf of
Mexico with other combinations of conditions of depth, climate, and
seismicity. Although construction costs have risen sharply in the past
two years due to inflationary pressures (25 to 35 percent) the
relationships expressed by the index are valid. As shown in Table 8B
development and production expenditures would likewise increase with
increased depth and more severe climatic conditions.

Except for the areas north of the Alaskan Peninsula, industry
engineers believe they have the technical know-how and the exploration
production equipment, expertise, and experience to undertake development
on most of the U.S. Outer Continental Shelf. However, severe storms and
seismic risks pose a grave threat to offshore development in Alaskan
Artie waters and engineering design improvements of current equipment
and consideration of new systems will undoubtedly be required.

Jack-up rigs will probably be used on the east coast offshore up
to depths of 300 to 350 feet. Semi-submersibles will be used for
exploratory drilling beyond that to a depth of 1,500 feet.

Projected water depth drilling and production capabilities for the
various areas to be leased are shown in Table 9.

Table 8. Offshore Exploration Drilling Expenditure Index Comparing

Gulf of Mexico (Moderate Climate, 650-Foot Depth) to Other Areas.

1.0 Equals $2.7 Million Per Well in 1974 Dollars (Source: Reference 15)

Drilling Expenditure Index

Climatic Conditioi
Feet (Meters) Mild Moderate^ Severe^ 75%3 i

Water Depth Climatic Conditions Ice Laden

A. Exploratory Drilling

650

200

0.8

1 .0

1.8

2.3

4.6

1,650

500

1.0

1.3

2.1

2.8

5.4

3,250

1,000

2.5

2.8

3.6

4.3

6.4

B. Development and Production

650

200

0.9

1.0

1,000

300

—

1.650

500

2.7

3.0

3,250

1,000

4.3

4.8

2.8 Unknown but
estimated to

6.2 be substantially
greater than

— "Severe" case.

10.2

'Moderate Climate - Gulf of Mexico, South
Atlantic, and California

^Severe Climate - North Atlantic and Gulf
of Alaska

^75% Ice Laden - Bristol Bay

^100% Ice Laden - Chukchi Sea and Beaufort Sea

^Climatic conditions include earthquakes.

Table 9. Present and Future '.''ater Depth and Earliest Dates
Exploration Drill inq and Production for United States Outer
Continental Shelf Areas (Source: Reference 15)

for

Area/Province

Maximum Water Depth Capabilitiei

Earliest Date

Exploration Drilling*

Production

Exploration Drill mg

Productiont

North Atlantic

At present, jack ups 300 350

At present, fined platforms

Now

Fi«ed 24 well platform m

feet Dtillships and semi sub

600 feet Undei water com

600 feet ready for produc

mersibles 1,000 1,500 feet

plet.ons (UWCt 1,200 1,500

Hon 4 to 5 years after field

Dvnamicallv positioned drill

feet In the future, platform

discovery and delineation

ships 2.500 3,000 feet In

capability 1,000 feet by 1979

Pipelines or barges required

the future, forecast capabil.

1980 UWC 3,000 feet by

for production

ties up 10 6,000 feel by 1980

1978 1980

Middle Atlantic

Same as North Atlantic

At present, fixed platforms
800 feet UWC 1.200 1.500
feet In the future, platform
capability 1.000 feet by 1979
1980 UWC 3.000 feet by
1979 1980

Now

Same as North Atlantic

South Atlantic

Same as North Atlantic

Same as Mirfrile Atlantic

Now

Same as North Atlantic

East Gulf

Same as North Atlantic

Al present, fi^ed platforms

Now

At present, fixed 24 well

Central Gulf

1,000 feet UWC 1,200

platform in 400 feet ready

West Gulf

1.500 te^l In the future,
UWC 3,000 feet by 1978
1980

for production 3 tO 4 years
after field discovery and
delineation Fixed 40 well
platform in 1,000 feet
ready tor production 6 to
8 years after field discov
ery and delineation In
the future, production
from UWC in 1. 000 3.000
feet by mid-1980's Be
cause of special treating fa
cilities required, sour (H2S)
hvdrocarbon production in
Area 4 mav add 1 lo 2 years

Southern Cal.

Same as North Atlantic

For Areas 7 and 8, same as

Now

For Areas 7 and 8, same as

Borderland

Gulf ot fyiexico For Areas

Gulf of Mexico For Areas

Santa Barbara

9 and 10. same as North

9 and 10, same as North

North & Central Cal

Atlantic

Atlantic Earthquake zones

10.

Washington Oregon

require special surveys and
engineering considerations

11.

Cook Inlet

Jack ups 300 350 feet

Platforms 600 feet for ice-

Now

At present, fixed 24 well

Southern Aleutian

Drillships and semi

free areas For seasonal

platform for icefree areas

Shelf

submersibles 1.200

ice areas such as Bristol Bay

in 600 feet ready for pro-

Gulf of Alaska

1,500 feet

and Lower Cook Inlet, plat-

duction A '/, to6 years af-

Bristol Bav S of
550 Lat

forms to 200 feel feasible.

ter field discovery and de-
lineation, in 200 feet ready
for production 4 to 5 years
Earthquake zones require
special surveys and engin
eenng considerations that
could cause delays Satel
hie UWC could extend
depth 100 200 feet m
most areas In the future,
production m ice free areas
in 1.500 teet feasible 1980
1985 Production in season
al ice areas beyond 200 feet
feasible 1980 1985

Bristol Bav N of

Jack ups 300 350 feet

Gravel islands and island

Now, selective

At present, production from

550 Lat

Drillships and semi-

type structures 50 feet

ly, with some

gravel islands and island type

Bering Sea Shelf

submersibles 1.200

Concrete or steel cone

modifications to

structures 4 to 5 years after

Beaufort Sea

1.500 feet during ice free

structures may be feasible

emsting equip-

field discovery and delmea

Chukch. Sea

periods Gravel islands

to 200 feet Dnllship cap

ment for speci-

tion, provided development

and island IV pe structures

ability may permit UWC if

fic areas

drilling from same island as

50 teet Land fast ice (as

latter can be designed for

enploration drilling In the

in Kotzebue Sound) may

potential bottom ice con

fulure, development cycle

be drilled Conventional

dmons.

periods for deeper water

offshore ngs not useable m

dependent on current R &

areas of heavy moving ice

D Additional overland

Anticipate that current

pipelines required for mov-

R&D proiecis such as ice

ing petroleum to southern

breaking drillships will ex

ports, since the pipeline

tend present capabilities

preiently under construction
will be fully used by pro-
jected North Slope produc-
tion forecasted from cur-
rent discoveries Earth-
quake zones require spe
cial surveys and engineer

rom indicalBd nmimum WKiter ctapHi capabilitv di/nfig Wv«>« vMStt^ar wMOnt

ing considerations

■ AII|»ck-up'i9iclfl'»tM]

T "Ri»clv tor pfoductton-

»nutmt all ctevelopmani Milt dri>i*d ba

ore initol production, one r.fl par platlorm D#w«lopmanl pariod

relaMd 10 numbar oi waHl.

drilling daplh. dnilirig condit

on* NurrtMt ot m«IIi not limttsd to easmplBt givan

2.2 OFFSHORE DEVELOPMENT PROJECTS

Five major projects are classified as entirely or principally
offshore in location. These include the surveying, drilling, and
transportation of oil and gas from the Outer Continental Shelf to
shoreside facilities for storage or processing. All these projects
require large "front-end" expenditures and some may be marginal in-
vestments. Location and use of these facilities offshore control, to
large extent, the location and type of onshore support facilities.

The offshore development projects presented in this section are:

2.2.1 Geophysical Surveying

2.2.2 Exploratory Drilling

2.2.3 Production Drilling

2.2.4 Pipelines

2.2.5 Offshore Mooring and Tanker Operations

2.2.1 Geophysical Surveying

The initial step in searching for potential petroleum deposits is
to analyze data about geologic characteristics of an area, derived
through a geophysical survey. The prime objective of that analysis is
to identify and locate reservoir rocks and structures (traps) in which
oil and gas could have accumulated. A knowledge of the subsurface is
also helpful in detecting near-surface conditions such as fault zones
(prevalent off California and Alaska) which pose possible hazards to
exploration and subsequent production operations.

Description

The seismic survey is the principal geophysical technique employed
by oil companies or their contractors for identification of potential
lease tracts that hold the most promise. Figure 9 schematically
illustrates the operation of a marine seismic system. During seismic
surveying operations, a ship with a crew of six to ten travels along a
predetermined path or grid towing signal -generating and recording
equipment. The signal generated by the energy source (usually air or
gas guns are used), results in a series of sonic pulses or seismic
waves, that travel through thfe water and are reflected and refracted by
the underlying rock formations. The returning sonic waves are detected
by hydrophones towed by the vessels and are recorded in digital format
on magnetic tape. The data is translated into vertical cross-sections
of each traverse. The cross-sections are then interpreted to determine
the presence of possible structural and stratigraphic traps. Subsurface
structure contour maps are prepared for selected formations which appear
promising.

One method for analyzing seismic data covering selected geologic
formations that has received wide industry acceptance is the "bright
spot" technique. This technique has been credited with the direct
determination of oil and gas prior to drilling in young sediments with a
relatively simple geologic structure. This method is based upon locating
large variations in seismic reflections, the greater the difference in
velocity between two formations, the greater the amplitude of the re-
flected energy. As the velocity in a petroleum-bearing sandstone
(reservoir rock) is lower than either a water-bearing or non-porous
sandstone, the presence of petroleum-bearing sandstone will cause a two
to five fold increase in the amplitude of the reflected energy. By
processing the seismic data to highlight the true amplitudes of the
reflections, it is possible to directly identify petroleum-bearing
formations. The data displays "strong events" or "bright spots" when
abnormally broad contrasts in velocity are present. While the technique
has been successfully employed in certain areas, it is not applicable in

all cases.

Figure 9, Seismic operations (Source: Reference 16),

SEISMIC VESSEL • 175'

AVERAGE LENGTH
OF TOW - 2 MILES

In addition to the deep penetration seismic survey activity described
above, other types of surveys are performed, such as shallow penetration
high resolution acoustic (sonar) studies to locate ocean floor geologic
hazards such as faults and mudslides. Results of these surveys are used
to aid in the selection of specific exploratory drilling and production
drilling sites.

Another type of survey involves the use of a magnetic sensor or
magnetometer to locate anomalies. The magnetometer is towed behind the
survey ship, similar to a seismic survey. The data is interpreted to
detect small warps or anomalies in the earth's magnetic field produced
by the different types of rocks. These anomalies indicate the structure
of subsurface rocks and petroleum-bearing strata.

Survey vessels often use gravity meters to measure slight changes
in the force of gravity attributable to different rocks of varying
densities over which the vessel passes.

The geophysical survey data collected by one or more techniques
described above may be supplemented by geologic studies of rock outcrops
on or near the sea bottom. The goals of these studies include age
determination, stratigraphic correlation assessment of the lithologic
character, and evaluation of mechanical properties (such as load strength
and compressibility), necessary for design of platforms and pipelines in
specific locations.

A process that may conclude this phase is drilling a Continental
Offshore Stratigraphic Test (COST) well. Core samples taken during
drilling are used to confirm conclusions about the rock layers and
structural composition of the rock. These tests, drilled from a
mobile rig, may penetrate up to 16,000 feet. According to USGS regu-
lations, stratigraphic test wells must be drilled off of any presumed
geologic structure and no direct testing for oil and gas is permitted.
The data obtained from analyzing the test must be released within 60
days after the initial lease sale in the area. Various well logging
tests and an evaluation of drill cores and cuttings can be used to
analyze the geologic sections that indicate the presence of source and
reservoir rocks and other factors which are indicators of possible
petroleum accumulations in the adjacent structures.

Two deep stratigraphic tests financed by a consortium of more than
20 companies were completed in the Baltimore Canyon trough in the spring
of 1976 and in the Georges Bank area during the summer of 1976.

Site Requirements

With the exception of COST holes, geophysical survey has no
significant onshore siting requirements. The survey vessel, requiring a
berthing space, is similar in size and needs to a commercial fishing

vessel. A rig to drill COST holes is identical to an exploratory rig,
described in Section 2.2.2, and has similar offshore and onshore sup-
port requirements.

Const ruction/ Installation

Vessels used in this activity are constructed at established ship-
yards. (See Section 2.3.2.) No unusual equipment or processes are
required. The installation of one COST well has the same character-
istics and impacts as an exploratory drill rig discussed in Section
2.2.2 following.

Operation

Survey vessels operate offshore, coming to dock to take on supplies
and fuel or to tie up between contracts. There is little that would
distinguish their operation from a deep sea commercial fishing vessel.
The operations of an exploratory drill rig are described in Section
2.2.2.

Community

Survey vessels have no discernible impacts on coastal communities.
Shipboard labor is contracted with the vessel offering no local employment
opportunities. Onshore businesses that provide the services needed by
this type of vessel, such as marine fuel and food supplies, (See Section
2.3.3) benefit from additional business. Effects of the exploratory
drilling rig, including data on employment and induced effects, are
minimal .

Effects on Living Systems

Geophysical surveys conducted offshore in deep waters do not
affect living resources, if conducted under established regulations.
Before modern techniques were perfected, dynamite was frequently used,
causing fish kills in small areas. Modern seismic techniques have not
caused any documented adverse impacts to living systems. Geophysical
surveys do not require any action to eliminate any potential for adverse
impacts to living systems. Effects of drill rigs on living systems are
described in Section 2.2,2.

Regulatory Factors

Outer Continental Shelf exploration and development activities are
generally managed by the United States Geological Survey. The COST

hole and associated exploration activities require specific permits from
USGS, the Coast Guard and the Corps of Engineers. In most respects
these are the same permits required for exploratory activity after
leasing. However, only one COST hole is drilled in a proposed leasing
area and precedes the definition of specific lease conditions which also
governs post-leasing exploration and development.

2,2.2 Exploratory Drilling

Exploratory drilling is the major activity of the exploration phase
of the offshore petroleum development process. This activity follows
the geophysical surveying of the offshore field. If the exploration is
successful, it is followed by production drilling (Section 2.2.3).

Exploratory drilling occurs after seismic surveying has determined
that a commercial potential for oil and/or gas exists in an area and
after a Federal lease-sale, in which tracts are awarded to oil and gas
companies on the basis of competitive bidding (See Figure 10). The
lease award gives the lessee exclusive rights and privileges to drill,
extract, and dispose of oil and gas deposits for a period of five years
or as long as oil and gas may be economically produced from the tract.

Figure 10. Exploratory drilling - project implementation schedule.

INVESTMENT COMMITMENTS: jite Purchase

Site Option(s) Taken

Start of
Construction

YEARS •••

PERMIT ACQUISITIONS:

Drilling

Acquisition of Use and
Location Permits

Operating Permits

Preconstruction Permits
(Includes EIS)

The petroleum company is obligated to proceed with the tract exploration
in a diligent manner or run the risk of losing development rights to the
tract.

Description

Exploratory drilling determines the location, extent, and quantity
of oil or gas. This phase differs from production drilling of wells for
the retrieval of commercial quantities of crude oil defined by exploratory
drilling. It also differs from Continental Offshore Stratigraphic Tests
(COST wells) which are deep drilling exercises seeking geological
information on the types of rocks, layers, and formation pressures in an
area to be leased.

The equipment used in exploration drilling is called a "rig." The
three major types of rigs used in offshore exploration are jack-up rigs,
semi-submersible drilling rigs and drill ships. These rigs are described
under Construction/Installation in this section.

Oil companies do not own drilling rigs; instead, they contract for
both rigs and crews from a drilling company. The equipment and crew
drilling a hole belong to the drilling company; the hole belongs to the
oil company.

Since the oil companies do not own rigs, they suffer no financial
consequences when work is not available. Instead, the oil companies can
wait until rig rental rates drop before drawing up contracts. Since
rates may be artificially low for some years, exploratory drilling in
speculative areas may increase. At present, though, the oil industry
has been reducing exploration and concentrating on development.

Site Requirements

Exploration is conducted within tracts leased by oil companies, in
areas suggested during geophysical surveying. There are no specific
site requirements for rigs as they are mobile. They use service bases
which do have site requirements and which are described in Section
2.3.1.

Construction/Installation

Offshore oil exploration today is significantly different in both
complexity and cost when compared with operations only 20 years ago.
The early offshore wells were drilled in relatively shallow and protected
waters. However, as exploration moved further offshore, it was necessary
to use larger steel platforms that were permanently affixed to a specific
site; this was usually accomplished by driving piles into the shallow

sea floor. The cost of a fixed platform, especially the expense and
difficulty of moving it, reached a point where it could only be employed
for production purposes and a new type of mobile rig had to be developed
for exploration.

A different type of platform was developed which entailed the
mounting of derricks on river barges which could be used in the shallow
coastal swamp areas of Louisiana. These platforms called bottom-
supported submersible platforms or simply submersibles proved to be
adaptable for shallow exploratory offshore drilling. The submersible
was generally towed to a well site and then sunk in shallow water.
After the drilling was completed, the submersible was pumped out,
refloated, and towed to a new location. Although developed more than 20
years ago during the infancy stage of offshore operations, there are
still about 20 of these rigs in use today. (However, submersibles are
of no value for exploratory drilling in the deeper waters of proposed
lease areas. )

Jack-up Rig: A type of bottom-supported rig which has evolved from
the submersible is the jack-up rig. By the end of 1976 approximately
180 jack-up rigs were in use worldwide. Figure 11 is a diagrammatic
illustration of this type of rig. The jack-up rig is essentially a
floating, barge-like hull that supports a platform. Drilling equipment
and crew quarters are mounted on the platform. Three legs, each up to
400 feet long, are fitted vertically through slots in the hull. While
the jack-up is being towed to a location, the legs are drawn up, but
when the rig is in place over the well site, the legs are lowered
mechanically or hydraulically until they reach the sea floor. The
platform is "jacked-up" until it has been elevated far enough out of the
water to be out of reach of most anticipated waves.

The dimensions and designs of jack-up rigs vary according to
weather conditions and water depths. Most jack-up rigs operate in water
depths less than 300 feet in calm conditions; they are located in
shallower water in areas with rough winter conditions. Jack-up rigs are
built and serviced at existing ship yards and other coastal steel
fabrication facilities. A representative rig currently in use might
have a hull that is about 230 feet by 230 feet and about 25 feet deep
with crew accommodations for almost 80 crew members and a drilling
penetration capability of up to 25,000 feet. A towing draft of 20 to 30
feet is normally required. Jack-up rigs are extremely stable and provide
a secure drilling position when used in the appropriate depths.

Semi -submersible Drilling Rig: The most recent development in
floating platforms is the semi-submersible; these have been operable for
more than 15 years. It floats, rather than rests on the sea bottom, and
is designed to minimize heave, pitch, and roll motions. In a semi-
submersible, the major buoyant support for the vessel is placed in
pontoons and risers which ride on and above the surface when a semi-
submersible is moving; when it is in the drilling mode, the pontoons are
sunk well below the water line by adding ballast.

Figure 11. Jack-up drilling rig for offshore exploration.
(Source: Reference 17).

^> — f>*'

Certain limitations are inherent in the design of semi-
submersibles. The addition or loss of weight on these vessels must be
carefully compensated for by altering ballast. Semi-submersibles are
usually towed to a drilling position, while newer semi-submersibles are
often selfpropelled. They require large facilities for construction and
servicing. As with jack-ups. they have a towing draft of 20 to 30 feet.

A semi -submersible can be anchored like a drilling barge, or it can
be dynamically positioned like a drill ship. Figure 12 is a diagrammatic
illustration of a semi-submersible. Some of the recently built semi-
submersibles are rather large; one vessel, for example, has a square
working platform some 200 feet on a side mounted on six hollow steel
columns 26 feet in diameter which in turn are mounted on two pontoons,
each 355 feet long, 36 feet wide, and 22 feet deep. A restricted area
of at least 1/4 mile and as much as 2 miles surrounding a rig may be
required as a buffer/safety zone to prevent fishing and other boating
accidents with the rig.

Drill Ship: A drill ship is self-propelled. The drilling platform
is situated in the deck; various internal compartments provide crew
quarters and storage space for equipment and supplies. The drill is
worked from a derrick through a hole in the center of the ship.

Modern drill ships such as the one illustrated in Figure 13 provide
greater stability than earlier predecessors. For example, the Glomar
40, a 450-foot ship displacing 14,500 tons, is designed for operations
in water depths ranning vrom 100 feet to 3,000 feet; it has the
capability of maintaining onerations in winds of fiO miles per hour
and waves of 5n feet

The modern technological response to the problems of surge and sway
came with the development of a sophisticated technique known as "dynamic
positioning." This technology involves the use of electronic devices to
take constant readings of a platform's precise geographic position with
relation to the ocean floor. The processed data is used to automatically
activate one or more of the steering propel lors or "thrusters" to keep
the platform in proper position over the well. Drill ships incorporating
these and other technological features offer the advantaaes of considerable
mobility and deep water drilling capability.

It is not possible to predict precisely which type of drilling rig
will be used in each OCS area; but the selection will depend upon a
tradeoff of factors including water depth, sea state, and the condition
of the sea floor. For anticipated United States OCS work the bottom-
supported submersible platform and the drilling barge can be eliminated
from consideration since the depth of most areas exceeds their capabilities.
Moreover, rough seas could easily capsize drilling barges.

Figure 12. Semi -submersible drilling rig for offshore
exploration (Source: Reference 18).

Figure 13. Typical dynamic positioned deep water drill ship
(Source: Reference 18) ,

TRANSMITTER I

TRANSMITTER 2

The jack-up rig is the only bottom-supported platform that may be
used in the OCS. Drilling rigs of this type are readily available as
they make up some 40 percent of the world's offshore exploratory rig
fleet. One of several important factors the operators will consider in
their selection of rigs is whether jack-ups are sufficiently mobile for
the job. Unlike other platforms, a jack-up rig is secured to the sea
floor to enhance its stability and to increase its resistance to wave
action. Preparing the jack-up for a move to a new location and then re-
securing it to the sea floor can take several weeks, depending on sea
and sea-floor conditions.

Cost factors aside,, the choice of rig for a particular OCS site is
based on a tradeoff between the demands of mobility and the desired
limits of vertical variation between the drilling platform and the
wellhead. If oply a few wells or wery deep wells are to be drilled,
mobility might be sacrificed for the greater stability of jack-ups.
However, if numerous wells are to be drilled, a floating platform may be
more feasible. Table 10 provides a comparative account of the three
major types of mobile exploratory drilling rigs--jack-up, drill ship,
and semi-submersible--by four major variables in selection (depth,
capability and other factors are judgemental and therefore vary from
source to source).

Operations

The exploration operations employed offshore, at sometimes great
depth, are an extension of the land methods that have developed over the
past seventy-five years. The only real difference is the specialized
hardware and the associated industries which developed in response to
that particular type of drilling.

All exploratory rigs have the necessary equipment on board for
drilling, but they must be supplied from service bases on the shore by
service boats and helicopters. The boats usually bring drilling muds
and drilling pipes on a regular basis if the distance from shore is not
excessively great; helicopters may be employed when distance to the rig
is a factor and too much time would be consumed in boat transit.
Helicopters are also utilized for interim trips, providing a quick,
efficient means of contact with the rig. Crewboats or possibly helicopters
are employed to change the drilling rig crews; this occurs typically
once every seven days or two weeks, but it varies with projects and
companies. Food is brought out at these changes, and solid waste is
collected from the rigs. Sewage is treated on board the rig or drill
ship and discharged into the sea.

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Community Effects

An exploratory drill rig is supported from temporary service bases
which are discussed in Section 2.3.1. The primary onshore effect to the
community from exploratory drilling oil is through employment and wages
generated.

Employment: Personnel requirements for semi-submersible rigs may
include 3 people onshore, 36 men on the platform working in each of 4
crews, 30 contract service personnel working in each of 2 crews, and 10
marine personnel. The total employment, therefore, is 217 of which 102
are on the rig at any one time [20]. Other employment estimates per rig
for the Mid Atlantic region fall as low as 113 employees [21]. Variation
in employment per rig varies with the type of equipment, rather than the
nature and location of the frontier area. For the Mid Atlantic lease
sale, 80 employees (37 percent) were estimated to be hired locally. An
additional 87 individuals were estimated to maintain temporary local
residences while the drill ships worked on site. The remaining 50
individuals would commute home during the seven days they were off duty
[20].

Total earnings for the 167 employees operating a semi-submersible
drilling rig, who reside in the local area, both temporary and permanent,
is estimated as $3,300,000, while those who left the area (50 employees)
earn approximately $1,000,000.

Induced Effects: The money going out for wages will have a
multiplier effect when it enters the local economy to purchase goods and
services. An average exploratory well takes approximately 3 months to
drill to a depth of 14,000 feet, but variables such as weather conditions
and sediment characteristics influence the length of time. Therefore,
the total effect on the local area depends on how many wells are drilled
both at one time and in total. In a promising field several rigs might
operate at the same time. If a single coastal port is much closer to
the offshore field, then supporting activities will concentrate at one
location, but if several ports offer similar advantages, then the total
effect may be dispersed over a wider area.

The effect on a local community may be less than it might
initially appear. Many temporary residents will send portions of their
earnings home. In addition, during the seven-day off period, they may
leave the local area for extended time periods. From the perspective of
the local community, these individuals require virtually no services.
Therefore, any local expenditures are positive as they are offset by
negligible public costs. In addition some local employment opportunities
are provided.

Effects on Living Resources

Exploratory drilling is characterized by major potential fish and
wildlife impacts from: (1) removal of ocean bottom habitat; (2) drill
cuttings and other discharges from the rig; (3) blowouts; and (4)
servicing requirements. Sponsor actions will be required during location
and operation phases to reduce drilling hazards.

Location: In spite of the relatively short duration that a rig
will be on location, the sponsor must make provision for: (1) eco-
logical potential of site; (2) disruption of bottom habitat particularly
live bottoms (coral reefs, etc.); and (3) interference with fish and
wildlife resources either indigenous to or migrating through the area.
Drill cuttings disposal can lead to such adverse ecologic effects as (1)
turbidity; (2) eutrophication; (3) toxification.

Operation: The sponsor's major environmental problem in operation
will be meeting pollutant discharge standards on waste disposal; e.g.,
drill cuttings, drilling muds, and brines. Solid wastes are returned
for on-shore disposal.

Regulatory Factors

Exploratory drilling takes place in an area of exclusive Federal
jurisdiction on the Outer Continental Shelf. The OCS Lands Act assigns
management responsibility to the Department of the Interior. The United
States Geological Survey manages exploratory drilling activities. Both
the Corps of Engineers and the Coast Guard must also issue permits
before exploratory drilling may proceed. The states have no formal role
in this process unless they have an approved Coastal Zone Management
Plan. (Coastal Zone Management Act of 1972, as amended 1976, Section
307 (c) (3) (B).)

Federal Role: After a lease sale on the Outer Continental Shelf,
the USGS may issue permits under Section 11 of the OCS Lands Act for
geophysical and geological exploration activities. The permit is issued
by the Area Oil and Gas Supervisor, USGS, under regulations found in
Volume 30 of the Code of Federal Regulations, Section 251.

The lessee must submit a plan with the Area Oil and Gas Supervisor
of the USGS which becomes the basis for specific permits. This plan
must include: (1) a description of drilling vessels, platforms, or
other structures showing the location, the design, and the major features
thereof, including features pertaining to pollution prevention and
control; (2) the general location of each well, including surface
and projected bottom hole location for directionally drilled wells; (3)
structural interpretations based on available geological and geophysical
data; and (4) such other pertinent data as the supervisor may prescribe.

In reviewing these plans, USGS has relied on the environmental
impact evaluation prepared by BLM and FWS prior to leasing. Normally
many of the suggested conditions or hazards are already accounted for in
lease stipulations developed by BLM, FWS and USGS, under Secretarial
Order 2974. To supplement these conditions, the Area Oil and Gas_
Supervisor may issue operating orders that govern exploration, drilling,
and production in leased areas.

The Fish and Wildlife Service contributes to the conditions which
may be attached to the exploratory drilling permit, BLM and FWS may
collaborate in designing biological surveys (in satisfaction of a lease
sale stipulation) to ascertain what effects the drilling would have on
"significant biological resources." Environmental assessment is
incorporated in the lease tract evaluation program managed by the
Bureau of Land Management.

The Fish and Wildlife Service is also asked to corraient on Corps of
Engineers and Coast Guard permits required for temporary and permanent
OCS structures. However .the Corps has interpreted its statutory
authority to apply only to navigational and security aspects, thus
excluding direct environmental consequences from Outer Continental Shelf
permit review; the Service is left with few opportunities to comment.

State Role: The 1976 Amendments to the Coastal Zone Management Act
added a provision that may bring states into this process insofar as
exploration brings associated coastal zone impacts. Section 307 (c) (3)
(B) requires that any "plan for the exploration or development of... any
area which has been leased under the Outer Continental Shelf Lands
Act... shall attach to such plan a certification that each activity which
is described in detail in such plan complies with such State's approved
management program "

Development Strategy

Data obtained from exploratory drilling is proprietary information,
owned by individual oil and/or gas companies. As such, this data is not
released to the general public, except upon the request of the company.
A copy of the findings, however, is given to USGS in compliance with
Federal regulations, but still remains proprietary.

In cases where a COST hole has been drilled in a frontier area
by a consortium of companies, information can be released to the public
either (1) after five years from the drilling date, or (2) within 60
days after a lease-sale is held within a 50 mile radius of the drilling
site. Within these specified time periods oil and gas, companies have
exclusive rights to the information obtained during exploratory drilling,
without obligation to make the data public. USGS can purchase the
information from the companies.

Each group of companies must obtain, analyze, and make judgmental
decisions on its own data with the hope that their assessments and
predictions on the location of oil and gas reserves are more accurate
than their competitors. The results and findings from exploratory
drilling will lead to field size determination and possibly production
drilling.

2.2.3 Production Drilling

Production platforms are located on offshore leased tracts to
extract petroleum resources and to house the crew, materials, and
equipment for offshore operations. Platforms are designed and constructed
to meet the specific requirements and conditions of the installation
site (see Figure 14). Concern about spill potential from operations on
production platforms is quite high in onshore areas. This concern, and
its effect on industry's strategies, will be emphasized in this section.
Production platforms are constructed in platform fabrication yards,
which are covered in Section 2.3.4.

Figure 14. Production drilling - project implementation schedule.

INVESTMENT COMMITMENTS:

Site Purchase

Site Option(s) Taken

YEARS •••

PERMIT ACQUISITIONS:

Acquisition of Use and
Location Permits

Start of
Construction

Begin
Drilling

Operating Permits

Preconstruction Permits
(Includes EIS)

Description

Production platforms may be fixed-pile platforms or gravity platforms.
Gravity platforms may be constructed with cement or steel as the major
component. All platforms consist of two parts: the deck and the jacket.
The jacket, which serves as a base supporting the deck section, is the
large skeletal framework often visualized when offshore oilfield develop-
ment is discussed.

The fixed-pile platform, commonly used in the United States, is a
steel framework. A fixed-pile platform is shown in Figure 15. Gravity
platforms, using concrete in the North Sea and steel off West Africa,
are rather recent innovations. The comparative advantages and liabilities
for selecting a gravity or a fixed-pile platform are discussed later.
At the present time industry anticipates all platforms used in United
States OCS frontier development will be the fixed-pile platform type.

The deck assembly includes modular units that may be interchanged
for each of the three operations conducted on a production platform:
production drilling, routine maintenance, and workover. Production
wells are drilled with a derrick. Figure 16 illustrates a production
platform drilling several wells. Pipe, drilling muds, and other necessary
equipment are periodically shipped to the platform and stored on board.
After wells are drilled, the drilling equipment is removed, so that only
crew quarters, monitoring, and safety equipment remain. As many as
sixty wells may be drilled directionally from a single platform.

Site Requirements

A production platform is situated within a leased tract, a square
usually encompassing approximately 9 square miles. A platform may
generally be situated at any location in the tract. This location is
restricted when the adjacent tract is owned by another company. Companies
that will be in different tracts but will share a common reservoir (oil
bearing geological structure) will try to establish a joint venture.
The U.S. Geological Survey also desires and may require joint ventures
("unitization") to achieve the Maximum Effecient Rate (MER) of the
reservoir. Several factors influence selection of a specific site
including subsea surface characteristics, reservoir characteristics,
ownership of adjacent tracts, and lease stipulations controlling
activities within.

The greatest single factor in selecting a location for a platform
is a subsurface geology. Bottom conditions, including surface sediments
and relief, limit feasible locations. Steep slopes and soft sediments
are undesirable bottom conditions. If oil is found under these surface
conditions, directional drilling, which has a horizontal range of
approximately one mile, is one method for overcoming the problem.

Figure 15. Example of a fixed-pile (production drilling)
platform (Source: Reference 22).

Figure 16. Typical di recti onally drilled wells
(Source: Reference 23)-

4000' - 6000'

Sea Level

Ocean Floor

Hydrocarbon
Reservoir

T
40' -80'

50' - 800'

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Directionally Drilled Wells

If the subsurface is hard and compact, as in the North Sea, a
gravity platform can be used. However, known geologic characteristics
of United States frontier areas indicate that soft sediments predominate.
Therefore, fixed-pile platforms will likely be used in all frontier
areas.

Construction/Installation (Drilling)

Determining the number of platforms that will be required, their
location, and the number of wells per platform is based on a careful
analysis of the data obtained during exploratory and appraisal drilling.
This analysis involves such factors as the number and thickness of
productive horizons, geographic extent, water depth, formation depths,
well pressures, etc. Marketing factors will also have a bearing in
setting production rates, transport modes, and time frame for recovery.

Production platforms are not standardized. They are custom designed
and engineered for a specific location. While many components, such as
motors, derricks, cranes, and housing modules are standard items, the
structure on which they are housed may have to stand in water depths
ranging from 50 to 1,000 feet (Figure 17). Platform engineering must
take into account depth, sea floor soil conditions, wave action (including
consideration of the 50 to 100 year wave), winds, sea floor stability,
and the weight of the structure.

In the Gulf of Mexico, the trend is to construct a master platform,
from which wells are drilled, and several satellite platforms on which
crew quarters, separators, or compressors, etc. are mounted. Each of
the satellites is connected to the main platform by a foot bridge. In
the North Sea where weather conditions are more severe and the water
depths are greater, thus increasing the cost of platforms, the trend is
to locate the wells and all direct support facilities on a single
structure.

Production drilling differs somewhat from exploratory drilling.
Exploratory rigs are readily moved from one location to another, but a
production platform is fixed in place for the life of the field. Modern
platforms are designed for drilling multiple wells. The largest platforms
have slots to accommodate as many as sixty wells. Exploratory wells are
usually drilled vertically; production wells may be drilled either
vertically or directionally. Directional or slant drilling requires the
deployment of special production rigs (that are mounted on the platform)
which can rotate the drill strings through the drive pipe or conductor
pipe that may be set at angles up to 30° in the sea floor. (See Figure
16) The bottom of a slant well may be more than a mile measured in the
horizontal direction, from the platform on which it was drilled.
Production rigs are usually designed with the derrick mounted on rails
so that after each well is completed, the derrick can be readily moved
over a new hole. The pace of drilling is slower for production than

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exploration, due to the need for perforating wells at the proper depth
for efficient pumping rates and the need to directionally drill some of
the wells to ensure as much coverage of the field as possible.

The series of actions that are required to connect a well with the
valves and pipelines for transporting oil and gas to shore is termed
well "completion." As each well is drilled, it is lined with concrete
and then capped with a seal until the pipelines or other shipment methods
are in place and storage tanks are ready to receive the output.

After the pipes, tanks, and processing facilities are installed,
sea water is pumped down the production casing of a well to flush out
any drilling mud which may have been left. A perforation gun is then
lowered into the casing. When it reaches a point opposite a stratum of
oil or gas-bearing rock, the gun fires explosive charges through the
casing and cement to establish a path for the oil or gas to flow from
the formation into the well bore. Another string of pipe termed pro-
duction tubing is put down the casing and serves as a conduit by which
the oil or gas come to the surface. Biocides are injected into the
formation to keep bacteria from clogging the flow.

The final operation of completing a well involves the installation
of a series of wellhead valves termed a "Christmas tree" that are
bolted to the top of the production tubing. Christmas trees may be at
ocean floor or on platforms. The two purposes of the Christmas tree are
to control the rate oil and gas flows into the tubing and to direct the
oil and gas to the various items of platform-mounted processing facilities.

Operations

After the wells are completed, the drilling equipment and most of
the crew quarters are removed from the platform. All that remains
visible on a production platform is a maze of pipes, valves, coils,
tanks, compressors, and other pieces of equipment which serve the
following functions:

1. to separate oil and gas from water which

has been trapped along with the hydrocarbons in
the reservoir rock;

2. in some cases, to separate the associated natural
gas from oil for separate flow into a pipeline
storage tank, or ship;

3. in other cases, natural gas is pumped back into a
reservoir through a separate injection well to
help maintain reservoir pressure and thereby
maintain production.

All processes and operations are continuously monitored by the
platform crew. Their sole functions are maintenance and emergency
control. Valves to regulate the flow of hydrocarbons can also be
controlled by radio from shore or a nearby platform.

A well may yield combinations of oil, gas, water, sand, and other
materials from the productive horizon. The purpose of the automated
treatment equipment on the platform is to separate these materials for
shipment ashore, reinjection back into the reservoir, or disposal. At
high formation pressures, most natural gas associated with oil is in the
liquid form. A separate pipeline is justified only if there is a
significant recoverable quantity. In that case, the oil and associated
gas will be separated. The gas may be processed on the platform to
further remove water and other undesirable components such as hydrogen
sulfide. However, if the quantity of gas produced is so small as not to
warrant the construction of a separate pipeline, then a single pipeline
would be used to transport both the oil and gas to shore. If the quantity
of gas is limited, in many cases the gas will be reinjected back into
the wells to maintain reservoir pressure to force oil to the surface; it
may also be used as a platform fuel.

Workover is a periodic operation to improve well production by
modifying downhole conditions (caused by sanding of wells and decline in
pressure). This operation, requiring crews and equipment including a
derrick, is usually conducted approximately ten years after initial
start-up (or when a well has production problems) and includes operational
and procedures similar to initial well-drilling.

A workover involves the removal of sand, water, and any other
substances which may accumulate in a well during production. During
workover operations the casing may be perforated at different depths to
bring in a new producing zone. In addition, safety equipment together
with any artificial pumping apparatus is removed for inspection and
overhaul before being reinstalled. Generally, during workover operations,
the wells immediately adjacent to the well being worked on will also be
shut down for safety.

Community Effects

The major effects of platform installation and operation are: (1)
increased local employment relating to onshore facilities; (2) increased
waterfront industry and general commerce.

Employment: A platform operation has two major phases with different
employment characteristics. Highest employment occurs from the time a
platform is first placed offshore until the last well is completed.
After completion, the operation of wells under the platform is monitored
by a much smaller work force. Estimates of platform employment during
production drilling vary from 65 to 217 workers. After the wells are
drilled employment drops to an average of 16 employees [25].

Induced Effects: Induced effects during the initial stage of
drilling production wells are similar to effects related to exploratory
drilling. Employment figures, percentage of crews from the local labor
pool, and onshore living patterns are all similar. Onshore support for
a platform may be more extensive during this phase, as supply needs are
greater and somewhat more diverse.

During the second phase, which begins after the well is completed,
employment both offshore and onshore declines rapidly. However, this
lower level of employment lasts approximately 20 years, and almost all
employees reside in the adjacent onshore area. Very few employees will
be new residents. This phase may be punctuated by workover, when
employment rises to levels of the first phase for a period of several
months. As they were during the initial stage, these employees are
primarily temporary residents who will leave the area upon completing
the workover; they have very little effect on the community.

Effects on Living Resources

Production drilling has effects of particular concern to fish and
wildlife from: (1) removal of ocean bottom habitat; (2) drill cuttings
and other discharges from the production platform; (3) oil spills; and
(4) increased activity from boats, pumps and other equipment.

Location: Production drilling is basically similar to exploratory
drilling except it may continue for a much longer period of time and
more drilling occurs from a single site, therefore concentrating drill
cuttings and mud. When drill cuttings are disposed overboard, the ocean
bottom topography is altered; organisms can become smothered from the
silts and sediments. Drill cuttings disposal can lead to increased
turbidity, eutrophi cation, and toxifi cation of local waters. Although
new technology has greatly reduced the chance of blowouts, oil spills
are still a distinct possibility from production drilling. Spill
potentials are reduced because much is known about various field pressures
from the exploratory wells previously drilled. Additionally there is a
chance of a spill from the transfer of oil between the production
platform and tankers or barges prior to pipeline construction. Increased
activity from boats operating between the shore and the platform, plus
noise from compressors, pumps, and other machinery may cause fish and
wildlife to avoid an area which under normal conditions they would have
occupied for reproduction, feeding, etc.

Design: The sponsor will have to incorporate design features into
a production platform which will exhibit the best in pollution control
technology, not only for the present to meet EPA's OCS platform discharge
criteria but also in terms of future developments. Appropriate designs
would allow easy insertion of pieces of machinery in anticipation of
future pollution control regulation.

Construction: The placement of production platforms, especially the
gravity type, will have to be done in ways that least disturb the aquatic
and benthic habitats. Where gravity platforms are used, bottom habitat
will be permanently removed, especially where a platform is used that
has a large "mat" or base as its foundation. In addition, the immediate
surrounding area will be affected by the construction operations performed
on the site. The sponsor will have to take appropriate construction
steps, as defined in advance tests, to ensure that neighboring areas
will not be affected by excessive turbidity, release of toxic materials,
physical disruption, etc.

Operation: The sponsor's major environmental problem in operation
will be in meeting pollutant discharge standards on waste disposal.
This includes not only petroleum discharges but also brines and sulfurous
mixtures which may be extracted from the well. These substances are
usually treated on the drilling rig, but it will be necessary to ensure
that equipment is always in efficient and proper operating order. EPA
may require the barging and disposal of drill cuttings to other ocean
disposal sites. Where drilling muds and cuttings contain more than
50 ppm hydrocarbons, they must be treated.

The sponsor will have to exercise diligent care and provide adequate
responses when it is determined that platform operations may be
interfering with fish and wildlife resources. Production drilling will
have to be planned to avoid disturbances to fish and wildlife activities,
such as reproduction, rearing of young, and migration. For example,
where a species traditionally congregates in a relatively small area for
breeding purposes, it may be necessary to institute alternative production
drilling schedules. This will allow the species to perform its normal
biological functions without outside interference. Such a scheme may
incorporate drilling at locations other than those of important species'
activities, which will be particularly important in the case of endangered
species.

Regulatory Factors

Production drilling on the Outer Continental Shelf occurs in a
geographical area under exclusive Federal jurisdiction. Except for
recent amendments to the Coastal Zone Management Act, which have yet to
take effect, (see Section 2.2.2), states have no formal role in the
management process for production drilling. The United States Geological
Survey in the Department of the Interior has primary Federal management
responsibility. USGS works through a regional agent called the Area Oil
and Gas Supervisor who has final authority over day-to-day management
decisions.

Federal Role: The leasing process, managed by BLM under the OCS
Land Act, results in lease stipulations based on comments by BLM, EPA,

FWS, OSHA and other Federal agencies. By virtue of Secretarial Order
2974, FWS may comment on, prior to USGS approval, rights of easements to
construct and maintain platforms, pipelines, etc.; design and plans of
same; on exploratory drilling; and on development plans. However their
primary concern is in disposal of drill cuttings and effluent discharges
which may affect natural resources in the area. These conditions are
then incorporated in the management standards enforced by USGS in the
post-leasing phases. USGS has the specific responsibility to inspect,
monitor, and document the day-to-day activities and operations under OCS
leases by on-site inspections. USGS 'checklists cover the full spectrum
of operational issues except platform-to-shore oil pipelines which are
regulated by other federal agencies, principally BLM and platform-to-
shore gas pipelines which are regulated by FPC.

Section 1333(f) of the OCS Lands Act extends the authority of the
Secretary of the Army (Corps of Engineers) to prevent obstruction to
navigation in the navigable waters of the United States, to artificial
islands and fixed structures on the Outer Continental Shelf. Pursuant
to this authority, the Corps of Engineers must approve a permit application
for any production platform. Section 10 of the Rivers and Harbors Act
of 1899 authorizes issuance of these permits. Permit review does not
include assessment of environmental effects, and is restricted to issues
related to navigability. Federal agencies such as FWS and USGS review
these applications prior to drilling and installation of production
platforms and related equipment.

The Coast Guard has the responsibility for the enforcement of all
applicable Federal laws on and under the high seas and navigable waters
of the U.S. It administers the laws and regulations to promote safety
of life and property, as well as to establish and to maintain aids to
navigation for the promotion of the safety on the high seas and waters
subject to U.S. jurisdiction.

The siting and operation of a production platform may be subject to
additional Federal regulation, particularly related to water quality and
discharges of oil and hazardous substances.

Development Strategy

The sponsor's strategies of production drilling include minimizing
construction and installation time and costs, engineering an optimal
design, and siting the platform in the best known location on the company's
lease holdings.

Platform construction costs are usually minimized by having it
constructed at the yard nearest to the field. Yards attempt to locate
to maximize attraction of business, as for example, the proposed yard in
Astoria, Oregon, which will sell platforms in both Alaska and California.
Fabrication of platforms is discussed in Section 2.3.4.

Engineering an optimal design has great flexibility. The platform
is designed for a specific site. The design includes locating the deck
above the 100 year wave height, determining the technological features
of the structure, ascertaining the number of wells to be drilled from
the platform, etc. As the petroleum industry moves into deeper waters
the costs associated with each platform rise dramatically. In these
deeper areas, it becomes increasingly critical for the petroleum company
to use fewer platforms to accomplish the same drilling and production
tasks. This strategy is implemented through directional drilling and
attaching as large a number of wells to a single platform as is possible.

Platform siting was discussed earlier in this section. Locating
the best site on a tract involves tradeoffs between the reservoir location
and surface conditions on the ocean floor.

2.2.4 Pipelines

Offshore oil and gas are brought ashore by pipelines. They are
usually put in by a pipeline-laying company under contract to an oil
company. Offshore operators use highly conservative design, emplacement,
and operating methodologies for offshore pipelines, apparently because
of the costs of underwater installation and the necessary environmental
constraints. Performance clearly shows that pipelines are safer and
more dependable than tankers and barges [26]. Also, pipelines allow for
continuous transportation of petroleum products; they are less dependent
on weather conditions which cause other modes of transportation to shut
down; production and transportation shutdowns are costly to the oil
companies and may result in interruptions of supply to onshore users.
It seems likely that pipelines will be used to transport oil from most
new U.S. offshore fields if permits for pipeline corridors and landfalls
can be readily obtained.

Figure 18. Pipelines - project implementation schedule.

INVESTMENT COMMITMENTS:

Site Purchase

Site Option(s) Taken

Start of
Construction

YEARS •••

PERMIT ACQUISITIONS:

jQBegin Use
of Pipelines

Acquisition of Use and
Location Permits

Operating Permits

Preconstruction Permits
(Includes EIS)

Planning and feasibility studies for the transportation of offshore
oil and gas to refinery and consumption centers onshore is initiated
simultaneously with the discovery and delineation of a new field. Once
the type, extent, and character of the reserves, and the characteristics
of the reservoir (porosity, permeability, water or gas pressure) are'
determined, from exploration drilling, production engineers can determine
the amounts of oil and/or gas that will ultimately be produced, production
rates over the life of the field, and the approximate location of
production platforms. With information on the production rates of
platforms and their approximate locations, planning for an oil and/or
gas transportation system can commence (See Figure 18).

Although much of this discussion focuses on offshore operations,
most of the environmental impact will be incurred nearshore and onshore.
The major impacts from pipeline construction occur in the nearshore
area. The impacts from the crew, materials, construction equipment, and
supply boats occur onshore.

Description

The pipeline is constructed of steel pipe sections, usually about
40 feet long, joined together by advanced welding techniques. Each of
the "joints" or pipe sections is coated with a corrosion-inhibiting
mastic compound and with a concrete covering which protects the pipe_
from damage that might occur during handling and laying operations; it
also provides weight and stability insuring that the pipe will sink.
Both the anti-corrosive coating and the concrete coating are applied at
an onshore pipe-coating yard before the pipe is transported to the "lay
barge" by supply boats (see Section 2.3.5).

System: The pipeline system consists of: (1) the source of oil or
gas; (2) a pressure source located on the production platform or in the
formation; (3) intermediate pressure sources along the line (if
necessary); (4) a landfall site; and (5) a delivery point. The crude oil
or gas may come from a single production platform or from a number of
platforms connected by smaller pipelines. In some cases, formation
pressures are sufficient to drive gas onshore; in others, compressors
are required. Pumping equipment is always required for oil pipelines.
Whether intermediate pressure sources are needed is determined by the
length of the pipeline, the diameter of the line, the quality and type
of fluid being transported, the differential elevations encountered over
the route, and the formation pressure.

Gas is piped to a gas processing facility, the shore destination,
on line between the landfall site and the market transmission line. Oil
is piped to one of two shore destinations, a nearby refinery or a marine
terminal, for transshipment to a refinery.

Site Requirements

The most important factor of the pipeline project is the selection
of the pipeline corridor. The major object is to minimize the total
capital and operating cost of getting the oil or gas from offshore to
the desired location onshore. Minimizing the transport cost of oil
usually, but not always, requires minimizing the length of the offshore
pipeline, because marine pipeline construction is considerably more
expensive than most onshore construction (pipelines through wetlands may
be as expensive as offshore).

Particular physical and environmental offshore obstacles to be
avoided include: deep trenches parallel to or crossing the shoreline,
heavy surf zones, soft bottom sediments, sediments subject to lique-
faction, extremely hard and rough bottoms, strong bottom currents, sand
waves, areas of seismic activity, live reefs, and heavy fishing areas.
This may cause a pipeline corridor to deviate from the shortest straight
line to the shore.

The Corridor: The preliminary technical assessment of potential
pipeline corridors by industry is begun after the size of the prospective
pipeline is determined. A number of corridors are selected which
originate in the offshore field and terminate at various shore locations
which are either feasible locations for transshipment terminals or
places where the pipeline can join an onshore pipeline. Each corridor
is assessed by developing a preliminary profile from hydrographic charts
and estimating the soil conditions and currents along the route.

From this preliminary study, the corridors being considered are
narrowed to several options to be considered in detail. Field recon-
naissance investigations examine the feasibility of each of the corridors.
Sidescan sonar is used to determine the presence of obstacles, debris,
and live bottoms. Hydrographic studies determine water depths and
bottom topography. Seismic surveys determine the near surface geology
and identify potential difficulties along each of the corridors. From
these reconnaissance surveys, a construction corridor is chosen by the
pipeline company.

The information developed during a reconnaissance survey, even
though allowing the final selection of a corridor, is insufficient
either to precisely position the pipeline during construction or to
develop engineering design and construction criteria. To provide this
information, a much more thorough survey is necessary; significant
financial commitments are made, and, as a result, location options begin
to be foreclosed.

During an engineering survey the detailed bottom profile, sub-
bottom stratigraphy, currents, and soils, along with items of special
concern such as faults, reefs, rock outcrops, and sand waves are investi-
gated. All of these parameters must be known to properly design the
pipeline so that installation will go smoothly and the pipeline will
operate safely and successfully throughout its intended lifetime.

Proceeding directly to an engineering survey of the chosen corridor
essentially removes the possibility of reducing the macro-level environ-
mental impacts of a pipeline, because they can only be eliminated
through siting the pipeline in an environmentally acceptable corridor.

Landfall to Destination: An oil pipeline does not require a wide
corridor of land once it comes ashore (nationwide, however, pipelines
may be the most land-consuming petroleum activity). The oil pipeline
will require a minimum right-of-way between 50 to 100 feet, some of
which may be purchased "in fee"; use of other rights-of-way may be
obtained by the pipeline company. Gas pipelines require a similar
right-of-way. The shore destination— a partial treatment facility or
gas processing plant--would be located inland from the landfall site.

Pumping stations are usually required near the landfall site for
pipelines transporting oil any appreciable distance. The station could
require 40 acres of land and could consist of an office, storage surge
tanks, and a pump station. An onshore transfer terminal (for barge
transshipment) would require a waterfront location of about 60 acres,
with a minimum 35 foot water depth by the frontage land. Another
alternative would be to have the oil repiped offshore to a marine terminal
where it would be transshipped by tankers [26].

Construction/Installation

Three methods are used for laying offshore pipelines:

1. The method used for most pipelines and for all large diameter
pipelines is to weld together 40-foot pipe

sections on board a lay barge and continuously lower them
over the stern of the barge via a "stringer" to the
ocean bottom. As new pipe sections are added, the barge
winches itself forward using a sophisticated multi-
anchor system.

2. A second method, the reel method, is used for laying
small diameter pipelines; traditionally 12 inches or
less, but now up to 24 inches. The pipe is welded together
onshore, wound onto a large spool, and then later unwound
for laying of the pipe. This method is often used for
flow lines between platforms.

3. The third method, not widely used, is to weld the pipe into
strands ashore, support these strands with floats, and
then tow the strands to location. On reaching location,
the pipe is flooded and welded onto the main pipeline.

Vessels: Almost all offshore pipelines with the exception of
gathering lines between platforms, are constructed using specially built
pipe-laying barges and pipe-laying ships. Pipe-laying barges are of
numerous types. Traditionally, they have been conventional barges on
which a pipe-laying rig was built, but standard ship hulls and semi-
submersibles are both in use. In the last few years, as offshore
operations have pushed into hostile areas such as the North Sea, pipe-
laying barges have grown quite large. One of the more modern barges,
Semac, measures 180 feet by 433 feet.

Along with the growth in the size of barges has been a trend toward
the construction of semi-submersible barges. Semi-submersibles can
better withstand heavy seas. Semi-submersibles can operate in seas
approaching 15 feet, whereas operations in a large conventional barge
must cease when seas reach 6 to 10 feet. Thus, semi-submersibles have a
considerably longer working season than conventional barges.

Coated pipe is brought to the barge in supply boats from a pipe-
staging area onshore. Two to three supply boats may be needed to keep
the barge supplied with pipe. Under good conditions, over a mile of
pipeline can be laid in a day. This is approximately the amount of pipe
which can be kept on the deck of the lay barge. Thus, continual resupply
from shore must be maintained or pipe-laying operations will come to a
halt. This is extremely costly since a lay barge may rent for up to
$200,000 per day.

The need for constant resupply means that a staging area will be
located as near as possible to the pipeline corridor with deepwater
access. Not only will transit distances and time be reduced , but more
importantly the weather window (required period of good weather) for
resupply may be greatly reduced. Short runs from the staging area to
the barge may even allow resupply during the lull in a storm.

On standard pipe-laying barges, the precoated pipe is put aboard
the barge, stacked, and moved joint by joint to the bow of the barge as
it enters into the lay system. The pipe ends are inspected for damage,
the joints are prepared for welding, each section is aligned with the
previous section at the "line-up station." and finally the welds are
made. Each successive joint is tested (usually by X-ray); the weld
joint is coated with "mastic," synthetic compound or concrete; and then
the pipe is launched.

All pipe-laying barges and ships are held in place and moved
forward with a multi -anchor mooring system. Most barges have from 12 to
14 anchors. Part of the anchors are being moved forward with anchor-

handling tugs to new positions determined by utilizing the ship's
navigation system and its radar, while the remaining anchors hold the
barge onsite. Once the new anchors have been set and additional
sections of pipe have been welded to the pipeline, the barge is winched
forward. Two or three anchor-handling rigs are required to service a
pipelaying barge (Figure 19).

The construction of a pipeline is significantly affected by weather
and sea conditions. A pipe-laying season may range from 220 to 270 days
for large lay barges; but heavy weather conditions may reduce work time
to about 40 percent of the laying season (e.g., in the North Sea, where
the most efficient barges lay approximately 37 to 50 miles of pipe per
year at a rate of 1.24 miles on a good working day [26].

Offshore pipelines are often buried for protection from mechanical
damage from currents and waves and from bottom fishing activity and
anchoring. A "bury barge" tows a sled which digs a trench by jetting
water at high pressure into the ocean bottom (Figure 20). Several
passes of the jet sled may be required in order to dig a trench of
appropriate depth, depending upon bottom conditions. Currently,
Department of Transportation regulations require offshore pipeline
burial of 3 feet in water depths less than 200 feet. Offshore gathering
lines, which come under the jurisdiction of the USGS do not presently
have burial requirements [26].

Construction procedures are different for "the shore approach," or
landfall, where neither barges and marine craft nor regular onshore
pipe-laying methods can be employed. Most of the generally used methods
include opening a trench from shore side to a water depth where barges
can operate, fabricating the pipeline string onshore or on the lay
barge, pulling the pipeline string into position, refilling and protecting
the ditch, and restoring the site. Heavy construction equipment, such
as trenchers and large winches, operates at the landfall site to pull
pipeline in ecologically fragile areas. Environmental damage from
pipeline construction can be partially mitigated by careful construction
and restoration techniques.

Pipeline Construction in Wetlands: In the process of moving oil
and gas from offshore to upland, an offshore pipeline often must cross
through wetland areas. Severe environmental alterations and damage have
occurred in wetland crossings. The long canals and resulting berms of
spoil left behind have altered water and nutrient flows, thus lowering
natural productivity and causing salt water intrusion, loss of wetland
habitat, and other problems.

Typical pipeline construction through wetlands is similar to offshore
pipe-laying with the exception that the barges are considerably smaller
and narrower and that a canal to allow passage of the barge is usually
dug using either a cutter head dredge or a dragline in place of the jet
sled.

Figure 19. Offshore pipe-laying barge
(Source: Reference 16)-

Figure 20, "Bury barge" or pipeline dredge barge.
(Source: Reference 16)

New techniques are now available for laying pipelines in wetlands.
One of these, the "push" method, eliminates the need for a pipe-laying
barge to enter the wetland; a V-shaped trench is dug through the wetland
(the width is dependent on the cohesiveness of the wetland soil). The
pipeline is then assembled and pushed ashore from the back of the barge.
(The pipeline can also be pulled from the far end with a cable attached
to a winch. )

Another new method uses a smaller channel than the traditional
method— a canal for a shallow-draft pipe-laying barge is dug with a V-
shaped trench in its center. The pipeline is fed into this trench and
covered as the barge advances across the wetland.

Onshore Pipelines: Previous sections have dealt with the pipeline
from offshore to the "shore destination," the first receiving point--a
gas processing plant or an oil transfer terminal or refinery. From this
point through the uplands area, the siting and construction of the
pipeline is not greatly different from other upland construction. There
are also close similarities with power transmission line corridors and
utility corridors insofar as the effects on the terrestrial environment
are concerned. The following information also applies to the sections
from landfall to shore receiving point. From the landfall to the
processing plant, refinery, or transfer terminal, the pipeline is of the
same dimensions as the pipe coming onshore. It is probably constructed
of the same material and may be given a protective wrapping but would
not be coated with concrete, thereby having a smaller overall size.

The corridor for onshore sections of the pipeline inland from the
shore receiving point will range from about 50 to 75 feet and follow the
shortest possible route. It will be buried at a depth of 4 to 6 feet.
Pipelines would normally avoid natural obstacles such as lakes or rivers,
but where necessary the pipeline may span large rivers or be installed
under smaller rivers and streams (Figure 21).

Figure 21. Directional drilling for pipeline installation under
rivers and streams (Source: Reference 27).

Operations

Day-to-day operations of pipelines are highly automated and require
work forces only for regular monitoring and maintenance.

After installation, pipelines must be monitored periodically. The
techniques include monitoring pressure gauges, metering pipeline flow,
and surface and air patrols of the routes. Timely leak detection and
control of a pipeline necessitate the use of monitoring systems which
are "redundant." The main focus of pipeline surveillance is a central
control station where the flow rates of the transmission line and of its
tributary gathering lines are monitored on a continuous 24-hour basis.
Pipelines are currently controlled by radio-activated equipment that can
cut off the flow of any part of a line which exhibits low pressures
indicative of leaking.

There are two important direct measurement tools that are used for
leak detection. One is a pressure sensor that measures pressure
reductions. If oil and gas are shipped in the same pipeline, the system
will only respond to leaks that cause a pressure decline of at least 30
psi. The second technique measures the volume of flow at two different
points on a line and can be used to verify that there has been no loss
of oil. If accurate and calibrated instrumentation is used and maintained,
this technique is extremely reliable.

A third method for detecting leaks requires the periodic patrolling
of the line by surface vessels and aircraft. This surveillance is
mandated every two weeks by government regulations. Although this
procedure is not an immediate response approach to a major leak, it does
provide a means of spotting leaks that may be too insignificant to be
picked up by direct measurement sensors.

Community Effects

A pipeline has attributes that may potentially affect a community,
depending upon corridor selection. However, with proper planning, such
as occurred in Scotland, these effects can be insignificant in onshore
communities.

Employment: Offshore, main pipelines are constructed from pipe-
laying barges, which employ about 160 to 175 people. Approximately 50
workers would be recruited locally [28]. This operation would lay
approximately one mile of pipe per day, and the longest lines would not
exceed 200 miles. Gathering lines are usually of much less total length
in a field, requiring fewer construction personnel. The length of time
required to construct a line depends on factors such as climate and
bottom conditions. Pipeline construction offshore will only provide
temporary employment in specific skills, such as welding, and is not a
likely attractor of new residents.

Onshore, the pipeline installation process is similar to that for a
sewer line or water main, employing a similar number of people with
heavy equipment to perform similar functions; however, metal pipe is
used and must be welded. An estimate of total employment is about 30 to
50 people. Onshore pipe-laying, because of the short time required and
because it is an additional contract for a firm already in that business,
would not stimulate any significant new employment.

Induced Effects: Pipe-laying will result in minimal effects on the
community. Pipe-laying barge workers will travel home or spend brief
periods of time in local temporary residences. However, with proper
environmental safeguards implemented during construction (except under
localized and temporary circumstances), the scale and character of these
pipe-laying activities have little significance for the local community
and its natural resources. More significant impacts will come from the
associated pipe coating yards (Section 2.3.5) and service bases (Section
2.3.1).

Pipe-laying companies tend to permanently employ their skilled
workers who travel from contract to contract with the barge. They do,
however, hire local labor to fill crew needs. A pipe-laying barge, by
the nature of its work, is only intermittently employed. Between
contracts, the boat is usually berthed in the nearest harbor or where
necessary repairs can be made. Most permanent crew members travel home,
and only a skeleton group remains to maintain the vessel and equipment.
Their presence should not affect the local economy to any degree.

Effects on Living Resources

An oil or gas pipeline, either offshore or onshore, has the follow-
ing characteristics of particular concern to fish and wildlife resources:
(1) underwater excavation; (2) subsea or terrestrial burial; (3) corridor
routing; (4) pumping stations; (5) landfall construction; and (6)
crossing sensitive habitats.

Location: In planning an oil or gas pipeline the sponsor tries to
locate the line along the shortest route, avoid rocky areas, and have as
much of the pipe on land as possible. Location will involve traversing
the ocean bottom, a landfall at a beach or wetland, and traveling across
land to a refinery or gas processing plant.

The sponsor must give considerable attention to environmental
constraints, particularly those affecting coastal ecosystems, because
construction of pipelines normally requires underwater dredging. The
underwater excavation is usually accomplished by a hydraulic "jet-sled"
which creates a liquid slurry of bottom materials allowing the pipe to
sink into the trench created. Excavated material is deposited beside
the trench and refilling of the trench is left to water currents and
sedimentation. Improper burial may leave the pipeline exposed and

vulnerable to fishing gear or anchors which may rupture the line causing
an oil or gas leak.

Corridor siting is of vital concern to fish and wildlife, because
pipeline construction through the habitat, especially in wetlands, may
bisect the area. This may create changes in the water circulation
patterns, salinity, temperature, or other parameters whose stability is
necessary to the survival of various species in the area.

Design: The high potential for adverse aquatic impacts of the
nearshore and landfall location requires that the sponsor exert maximum
care in design of the landfall, including provisions for: (1) maintaining
the natural shoreline; (2) minimizing dredging; (3) arranging proper
disposal of spoil; (4) avoiding wetlands; (5) reducing problems of
runoff discharge; (6) backfilling; (7) maintaining tidal exchange; (8)
restoring vegetation; and (9) construction and maintenance of bulkheads
or pilings at all crossing of natural tidal creeks and rivers. Roadway
and maintenance corridors should follow the same precautions.

Construction: The sponsor must perform the terrestrial construction
with the utmost care to protect adjacent aquatic and terrestrial areas.
The scheduling of construction must avoid sensitive annual periods of
species, including breeding/spawning, rearing of young, etc. Operation
of heavy equipment must be performed to protect fragile environments,
such as barrier beaches, wetlands, and productive shallow flats. In
many cases, especially in landfall areas, mats can reduce the impact of
heavy equipment operations and access to construction sites can be
accomplished by existing service roads.

Dredging of pipeline trenches in coastal areas should be done in a
manner which will minimize turbidity and sedimentation, such as sediment-
screen employment and other techniques. If pipeline trenches are dug
through wetlands, excavated material should be replaced in the trench
instead of along the sides where it can interrupt water flow and change
circulation patterns. In addition, new fill material should be added
where necessary to keep the elevation of the trenched area the same as
the surrounding wetland.

Terrestrial crossings require that special care be taken to reduce
effects on wildlife and endangered species, their habitats, and the fresh-
water system. A major factor is prevention of erosion and sedimentation
into local streams and rivers where fish habitats could be adversely af-
fected. River crossings can be particularly complicated and can yield un-
necessary impacts to downstream areas. Use of the subterranean drilling
method virtually eliminates disturbances. As part of the construction, a
restoration program should be instituted to revegetate the excavated
areas as soon as possible. Temporary stockpiling of dredged material
from trench construction should not be on river bottoms or productive
riverine habitats.

Operations: The sponsor's major environmental concern in the
operation of a pipeline will be the prevention of pipeline rupture and
subsequent oil spills.

Normally, problems associated with the pipeline corridor are by far
the most important consideration affecting fish and wildlife resources
and the one consideration that the applicant will have to give the most
effort to solving. Designing the landfall to avoid shoreline disturbances,
particularly of wetlands, will be next in importance. Requirements for
terrestrial construction and operations will likely come next. However,
depending upon the locale and other specifics, the priority of the above
may change dramatically.

Regulatory Factors

The pipeline contractor seeks to minimize the onshore and offshore
environmental impacts of the placement of the pipeline by choosing an
environmentally acceptable corridor as the site. The location of the
pipeline may ultimately depend upon the sites selected for any natural
gas processing plant (discussed in 2.4.3) or refinery (discussed in
2.4.1) or the location may depend on existing onshore pipeline
distribution systems.

The oil and gas company and pipeline contractor must consider both
state and Federal permits and sometimes other local regulatory
requirements before choosing a corridor.

State and Local Role: Responsible state and local entities may
seek to minimize onshore impacts of pipeline construction by requiring
the contractor to employ new techniques for laying pipelines, especially
in wetlands. States may do this under siting laws which apply in
addition to required Federal permits. The contractor may need to obtain
state permits and certification for related construction activities as
well .

State jurisdiction over the siting of any pipeline ends at the
limits of the state's territorial waters (three miles, except for three
leagues off Texas and Florida Gulf Coast).

Federal Role: Dredging and filling in navigable waters of the
United States require permits from the Corps of Engineers authorized
respectively under Section 10 of the River and Harbors Act of 1899, and
Section 404 of the Federal Water Pollution Control Act Amendments of
1972. The FWS reviews these permit applications under the Fish and
Wildlife Coordination Act and NEPA. The Service seeks to protect fish
and wildlife and their habitats, especially those of endangered species.
A sponsor would also need to obtain an easement for a right-of-way for
pipelines, either from BLM for lines from lease tracts to shore or over

Federal lands, from USGS for gathering lines within a field, from state
in state waters, or from private owners along a proposed right-of-way.
The Federal Power Commission issues certificates for construction and
operation of gas transmission lines (Table 11).

Gas pipelines are also subject to Federal safety standards described
in 49 Code of Federal Regulations. They are promulgated under the
Natural Gas Pipeline Safety Act (NGPSA), and govern the design,
construction, operation, and maintenance of gas pipeline facilities and
the transportation of gas in or affecting interstate or foreign commerce.
These safety standards apply to gas pipeline facilities and to the
transportation of gas in its liquid or gaseous state onshore, on lands
beneath navigable waters, and on the Outer Continental Shelf. The
Office of Pipeline Safety (Materials Transportation Bureau), Department
of Transportation, implements and enforces these regulations.

Offshore gathering lines are now regulated primarily by USGS under
lease area development plans. A Memorandum of Understanding between the
Departments of Interior and Transportation, published on June 11, 1976,
in Volume 41 of the Federal Register, page 23746, clarifies the regulation
of offshore gathering lines. The Materials Transportation Bureau in the
Department of Transportation has proposed to amend 49 Code of Federal
Regulations, Part 192.1 to expand that Part's coverage of offshore
gathering lines. The authority for the proposed regulation is the
Hazardous Materials Transportation Act, which includes gas pipelines
which are not subject to the jurisdiction of the NGPSA.

Development Strategies

Numerous alternatives for the transportation of oil and gas are
available.

When the existence of a commercial oil field is established, a
decision must be made on the best method of transporting the oil to
shore. The oil can be transported either by pipeline or by bulk carrier,
such as an oil tanker or barge. Evaluation of many variables is required
in order to optimize the transportation scheme. Among these variables
are oceanographic and meteorological conditions affecting tanker
operations, volume of oil to be transported, and distance from refining
areas [26]. Economics will principally decide which option of many is
chosen. In some cases, barge or tanker transport will be used initially.
Later, a pipeline may be built after production from the field and
nearby fields passes the threshold value which can economically justify
its construction.

Alternatives: Among the alternatives for transporting oil and gas
are the following:

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102

1. As oil is produced, it is pumped immediately to shore
through a pipeline: onshore the oil can be (1) pumped
through pipelines to refining centers, or (2) stored
in large tanks at a transshipment terminal where it
will be pumped onto tankers for transport to distant
refining centers.

2. The oil can be pumped to a central offshore storage
tank from which tankers transport the oil to refineries;
the oil is transferred from the tank to tankers via a
"single point mooring system." (Section 2.2.5)

3. The oil is stored in large tanks within the platform's
base from which it is loaded via a "single-point
mooring system" onto tankers.

4. The oil is pumped from the platform directly through
a "single-point mooring system" to a tanker; when the
tanker is filled, it departs and another takes its
place (this method has serious storage and cost
problems and is unlikely to be used).

5. Oil is pumped from the platform onto a "ship-
shape" barge attached to a "single-point mooring
system"; the oil is transported to shore by trans-
ferring the oil from the barge to tankers shuttling
to refineries.

Bulk carriers have a higher environmental risk than pipelines and
are not usually an economically attractive substitute for pipeline
transportation, if sufficient quantities of oil are available to satisfy
pipeline construction. Offshore loading facilities are required as well
as storage facilities to handle the oil produced while bulk carriers are
not loading. Transportation via bulk carriers is subject to interruption
by bad weather which may necessitate shutdown of production and inter-
ruption of supply. These factors discourage usage of bulk carriers.
There is, however, currently a surplus of tankers, and operators may be
reluctant to use pipelines unless there is a large cost-offset. Tankers
also provide flexibility.

There are considerably fewer alternatives for the transport of gas
to consumption centers. This is largely because gas is such a high-
volume to value commodity. Its volume can be reduced in order to reduce
its cost of transport, but costs are incurred in processing to reduce
volume. The ship alternative requires the gas to be liquefied prior to
shipment by a process using very low temperatures. This requirement,
together with the special carriers needed to move the liquefied natural
gas ( LNG) greatly increases capital cost. The result is that pipelines

103

are preferred. If gas is not of sufficient quality to justify pipeline,
it is put back into the structure to increase oil recovery or, if not
useful, flared.

Investment Tradeoffs

If the offshore oil reserves are large a pipeline will almost
assuredly be constructed. If the field is far offshore and remote from
other oil fields, a pipeline may not be possible and alternatives 2 to 5
(described above) will be given careful consideration. The economics of
using tankers for floating offshore storage tanks have improved enormously
during the past six years due to improvement in design and construction
of these offshore storage facilities. Alternative two is additionally
attractive if the oil stream arriving from offshore were to be split,
some being refined in the adjacent region and the rest being transported
elsewhere for refining.

Unless an offshore gas field is large enough or near enough to
shore to justify a pipeline to shore and from there to consumption
centers, it will probably not be developed. Liquefaction of gas to
reduce its volume for transport is expensive, and probably prohibitively
so, when done offshore. Development of an offshore gas field becomes
slightly more feasible if a pipeline from offshore to an onshore lique-
faction plant can be justified, but the associated capital costs may
also preclude development. In the North Sea, every gas field which has
been developed is piping its gas, not to the nearest onshore location
for liquefaction and shipment, but considerably farther to demand centers
in England and Germany.

The determination of the proper diameter for an offshore pipeline
involve economic tradeoffs between the cost of pipe, the feasibility
and cost of erecting interim booster pumping platforms offshore, and the
cost of operating pumping stations. A given pipeline can handle greater
volumes of oil or gas if more and larger horsepower pumping stations are
added along the pipeline route.

Corridor selection is made so as to minimize the total cost and
logistical difficulties involves in constructing and operating an entire
oil transport system. Therefore, it is important that the selection of
a pipeline corridor be evaluated in the context of its full potential
impact on an area.

The selection of a pipeline corridor is often considered simulta-
neously with the selection of a site for an oil transfer terminal and,
to a lesser extent, the onshore support base (including materials staging)
for the construction of the pipeline. Decisions as to the acceptability
of the corridor must be made on the basis of the whole range of impacts
and changes the corridor will induce during its construction and
operational lifespan.

104

During site selection, great flexibility exists in locating
facilities to mitigate environmental impacts especially in remote areas
such as Alaska. For instance, if commercial quantities of oil were
found in Lower Cook Inlet, a pipeline could be built to onshore
facilities on either side of the inlet. The western shore of Cook Inlet
is a wilderness area where environmental impact would be highest; whereas,
the lightly populated eastern shore which has roads and some community
infrastructure would be less environmentally harmed.

Onshore development in a wilderness would probably cause far more
significant impacts over the long term than would development in an
urban area or even a rural area.

105

2.2.5 Offshore Mooring and Tanker Operations

Transportation of petroleum, when fields and markets are separated
by water, is often done by tankers. As tankers have increased in size,
new systems for transferring petroleum between vessel and shore point
have been devised. The increased draft of tankers has made fewer ports
available for landing and for direct transfer into shore storage terminals.
A technological response to this need has been offshore mooring systems,
termed single point mooring (SPM), which are connected to storage terminals
by pipelines (see Figure 22). SPM related problems with tankers are
discussed along with other regular problems of tankers used in inter-
national and national transport of petroleum products from port to port.

Figure 22. Offshore mooring - project implementation schedule.

INVESTMENT COMMITMENTS:

Onshore
Site Option(s)

Onshore
Site Purchase

Start of
Construction

YEARS •••

PERMIT ACQUISITIONS:

Begin
Operation

Acquisition of Onshore
Use and Location Permits

Operating Permi ts

Offshore and Onshore
Federal Reconstruction
Permits (Includes EIS)

106

When located at sufficient depths, single point moorings eliminate
the need for deepening existing harbors, channels or turning basins,
future maintenance dredging or the extension of existing piers. The SPM
is anchored to the seabed and the tanker moves freely around the mooring
to a position of least resistance to wind, waves and currents. This
enables a tanker to remain moored in relatively severe weather conditions.

SPM systems may be a practical, and environmentally acceptable,
alternative to traditional port facilities for transferring cargoes
between the shore and Very Large Crude Carriers (VLCC) and Supertankers.
While more than 150 SPM's are operating in oil producing and consuming
areas around the world, none have yet been installed in the United
States.

Several SPM Systems are planned for the United States. We rely on
overseas supplies of crude oil for over 40 percent of our needs. With
approximately 65 percent of the world's known producible oil reserves
located in the Middle Eastern and African nations, VLCC's, which range
in size from 160,000 DWT (dead weight tons) to 500,000 DWT, represent
the most economical means of transporting large volumes of crude oil
over large distances. The majority of U.S. harbors, however, are currently
unable to receive VLCC's. The controlling depth of U.S. harbors, except
for Puget Sound and the Virgin Islands, is 52 feet or less which precludes
all VLCC's larger than 160,000 DWT [29]. Figure 23 illustrates channel
depths for major oil terminal ports in the United States.

SPM's are planned for two offshore "ports" on the Gulf Coast, LOOP
(Louisiana Offshore Oil Port) located 18 miles south of Grand Isle,
Louisiana, and "Seadock," 26 miles south of Freeport, Texas. Another
SPM is contemplated as part of the development of the Santa Ynez field
near Santa Barbara, California.

Description

SPM: these are floating mooring systems located offshore in water
depths of 50 to 150 feet. A tanker is moored to the SPM by lines, or a
rigid yoke, connecting its bow to a buoy or tower structure floating on
the surface. Oil can be transferred to and from onshore and offshore
storage tanks by submarine pipelines connected to the SPM and the VLCC.
Vessels usually can be moored at SPM's without the aid of tugs. Oil can
be pumped by onshore pumping stations, offshore pumping platforms or by
the VLCC itself. Offshore pumping platforms are constructed either when
SPM's are located a considerable distance offshore or when high pumping
rates are required (Figure 24).

There are two types of SPM systems in widespread use: the Catenary
Anchor Leg Mooring (CALM) and the Single Anchor Leg Mooring (SALM).

107

Both allow the attachment of mooring lines from the bow of the ULCC to
a swivel on a mooring buoy which is attached to the sea bottom. The
mooring buoys are equipped with safety lights, bells and fog horns to
reduce the chances of damage and are designed to withstand considerable
impacts.

Figure 23. Controlling water depths (feet) at major United States
ports (Source: Reference 29).

,OI Bay 1401
Ballimors (42)

Hampton Roads (45)

Poflland (451
Boston (40)

New Yo(k (35-451
Philadelpltia (40)

Los Angeles-

Lonq Beach (50-621 \

I JacksonviKe (40)

Vi 'Mobile (40, \
\ % \ Tampa T

•v Port Evetgladel (40)

The CALM system (Figure 25) was developed by the Offshore Marine
Terminal Company and the cylindrical, steel buoy has a diameter of 30 to
50 feet. Pre-stressed catenary chain legs anchor the buoy to piles fixed
to the sea floor. A CALM system is placed in depths ranging from 50 to
120 feet depending on the draft of the largest VLCC to be served [26].

The SALM system (Figure 26) consists of a cylindrical steel buoy
approximately 13 feet in diameter and 56 feet high, attached by an
anchor chain to a single mooring base fixed to the sea floor. The
mooring buoy has an upper chamber available for storage and a lower
ballast chamber [26].

108

Figure 24. Simplified schematic of offshore facilities
single point mooring system (Source: Reference 30).

Figure 25. Catenary Anchor Leg System (CALM)
(Source: Reference 26) .

tutil*«liic nn imn-....

AWCHOII CM*INS

aat rg sctit

109

Figure 26. Single Anchor Leg Mooring (SALM)
(Source: Reference 26).

MOORING 8U0Y-
FENOERING.
M.L.W. EL. 00'

-NAVIOATION LIGHT

CHAIN SNIVEL
SHAFT UNIVERSAL JOINT

FLUID SWIVEL ASSEMBLY

8'-6" OIA- RISER SHAFT

FLOATING HOS:S

BASE UNIVERSAL JOINT
MOORING BASE -^
SEA BOTTOM

BODY FLOAT (TYP-)
SUBMARINE HOSES
-BUOYANCY TANK

10" OIA- CARGO TRANSFER PIPE

SPECIAL REINF' SEA LINE
CONNECTING HOSE

SUBMARINE PIPELINE

aoi 10 SOU

Tankers: the modern tanker is a highly developed and specialized
ship type designed to transport various kinds of liquid cargoes.
Normally, a tanker is designated to carry either a "clean" (product) or
"black" (crude) oil. The "clean" oils are aviation fuel, gasoline,
kerosene, gas oil, high speed diesel oil, gas turbine oil, to name a
few; while the "black" oils consist of crude oil, and residual oils.
"Clean" oils are usually carried in the smaller ships, the bulk of their
work being of a short haul coastal service while the 'black" oils are
carried in the larger ships, their work being more of a long haul nature
from the oil wells to the refineries.

110

Site Requirements

The ideal location for an offshore mooring would be a nearshore
area protected from strong winds, waves and currents, with a natural
water depth greater than the draft of the largest vessel expected during
the life of the project. All SPM's are located where the sea floor
geology is stable and capable of anchoring the SPM firmly in place.

A major siting criterion is the route of the submarine pipeline,
landfall, and onshore pipeline or terminal. Considerations for pipeline
siting are discussed in Section 2.4.2.

SPM's are most commonly found in newer oil areas in foreign countries
where other deep water port facilities are impractical or economically
infeasible. In older producing and market areas, such as the United
States, SPM's may be built to serve existing or proposed oil and gas
related facilities. They will be located near pipelines and storage
terminals, and to a lesser extent, refineries. The siting of oil storage
terminals is presented in Section 2.3.6, and that of refineries in
Section 2.4.3.

Construction/Installation

Both tankers and SPM's are fabricated at shipyards. Conventional
equipment is used and construction activities introduce no major
disturbances to the area. Installation of the SPM requires support
tugs, supply ships and a derrick barge for driving the piles that attach
the SPM base to the sea floor. Installation of the SPM itself is
relatively uncomplicated and has little ecologic impact. Critical
submarine pipe laying and burial are covered in Section 2.2.3.

Operations

SPM: oil is loaded and unloaded through a pipeline and floating
hose attached to the vessel's manifold. CALM systems have been built
with multi-purpose manifolds and floating hoses to facilitate several
operations simultaneously, such as refueling and crude oil transfer.
After the transfer of fluids, the floating hoses retract to the buoy.
The oil being transferred in a SALM system is pumped through a floating
hose, a pipe within the anchor leg and the submarine pipe to an onshore
storage tank.

A sophisticated monitoring system safeguards unloading and loading
activities. Regular inspections are scheduled to check the structural
stability of the entire SPM system and pipelines to sufficiently protect
against ruptures and leakage.

Tankers: Tank cleaning and deballasting operations are environ-
mentally harmful. Tank cleaning is required when:

1. A cargo is to be carried which will not tolerate residues
from a previous cargo.

2. A vessel is to undergo repair work which by its nature
requires gas free conditions.

3. Clean ballast is to be taken on board.

Previous to the development of the large super- tanker, the prevailing
custom was to clean all tanks, the object being to prepare the vessel to
carry a different cargo. A tanker will generally operate with as many
full tanks as possible, depending on the density of the oil, on one leg
of its voyage and will return with ballast water in certain tanks, that
if no commercial cargo is available, insure that the vessel is seaworthy
and capable of safe navigation [31].

The quantity of ballast water taken on is large, sometimes as much
as fifty percent of the loaded deadweight tonnage. The actual amount
and disposition of this ballast will depend upon the following factors
[31]: (1) stability and trim, (2) propeller immersion, (3) machinery
vibration avoidance, (4) length of voyage, (5) hull stresses, (6) steering
characteristics, and (7) sea state.

A normal ballasting procedure is as follows: the vessel upon
discharge of its oil, takes on ballast water either at the dock or
immediately upon departure. This water is placed in uncleaned empty oil
tanks according to an optimum profile plan as indicated by the above
factors. Upon departure, the crew embarks on the tank cleaning operation
of the still empty tank in preparation for taking clean ballast on
board. After certain tanks are cleaned, they are filled with clean
ballast and the dirty ballast tanks are then emptied by pumping overboard.
The reason for this is that the discharge of dirty ballast water is
prohibited in coastal areas by either international or local pollution
laws, therefore if a vessel is to maintain its seaworthiness for the
entire length of the voyage, it must be in a position to de-ballast only
clean water while coming into port [31].

The actual mechanics of the tank cleaning operation are accomplished
by spraying cold or heated high pressure sea water into the cargo tanks
through tank cleaning heads. Upon completion of the operation, the
clean tanks are filled with sea water while the dirty tanks are pumped
dry. Cleaning water sprayed into the dirty tanks will dislodge
much of the oil adhering to structural members and, if directly
pumped overboard, will result in significant discharges of oil.
At present, this practice has been restricted by recent legislation
limiting the quantities of oil pumped overboard. Reliable sources
indicate that the amount of oil left as clingage in cargo tanks is

112

approximately 0.4 percent of the cargo deadweight. In addition, consider-
able amounts of oil may remain in cargo tanks after cargo pumping
operations as a result of plugged limber holes and the resulting poor
drainage past structural members [31].

The recent "load on top" technique reduces the amount of oil
discharge to within the permissible limits of the present law. This
technique consists of pumping the oil residue from the tank cleaning
operation into an empty cargo tank. This mixture is then allowed to
separate by gravity (the oil normally is on top since its density is
usually less). Water is pumped overboard until the interface approaches
the suction line. The remaining fluid is a mixture of about 75 percent
oil, 25 percent water. This is transferred to a cargo tank in which new
oil is loaded on top. In the event that the new oil is of a different
type, then additional measures must be taken such as pumping the fluid
ashore or using it as fuel in the vessel's propulsion system after
further separation.

The problems associated with this system relate more to practical
application than to theory. Analysis of this technique indicated that
effective oil/water separation may be adversely influenced by the follow-
ing [31]: (1) severe sea state conditions; (2) insufficient separation
periods due to short voyage (one tanker operator recommends 10 to 12
hours); (3) agitation due to the pumping operation itself; (4) cargo oil
having a specific gravity close to sea water; (5) inaccurate overboard
discharge measuring devices; and (6) human error.

Community

Moorings are located offshore and require limited onshore coastal,
facilities, making small increases in demand on public facilities. In"
the United States, SPM's are anticipated in locations where onshore
facilities, including tank farms, pipelines, and refineries are already
in place. SPM's merely offer a less expensive way to transfer crude.

Employment: During construction, an average total work force of
less than 1,000 will be employed at each of the two proposed offshore
terminals (LOOP and Seadock), peaking at approximately 1,500. A majority
of the labor force will be employed in fabricating and installing offshore
facilities, and will not affect local communities. A smaller work
force, up to 380 workers, will construct the onshore facilities, including
docks, warehouse and terminal facilities. Established contractors and a
local labor force should conduct a majority of this onshore work.

Employment upon completion is estimated at 300 workers to maintain,
operate and monitor the facilities [29, 30].

Induced Effects: Demand for services at the facility and by new
residents will strain a local economy in a rural region. In addition,

113

if the large offshore work force comes onshore during non-work periods,
their demands for services could extend local facilities. A majority of
the fabrication work will be completed in established fabricating
facilities and should not affect the adjacent onshore community.
Operations will have more substantial effects, but the scale will depend
upon the number of new residents attracted to the area. Total effects
will be tied into the additional industry and services attracted to the
local area by the presence of this facility.

Effects on Living Systems

An SPM has the following characteristics of particular concern to
fish and wildlife personnel: (1) oil transfer from Very Large Crude
Carriers (VLCC); (2) pipeline to shore; (3) oil storage terminal; and
(4) pumping platform. Normally, problems associated with selecting the
pipeline corridor are the most important consideration affecting fish
and wildlife resources, and the one that the sponsor will have to give
the most effort to solving. The sponsor of the single point mooring can
be expected to route a pipeline with the shortest distance to the storage
terminal area. However, depending upon several factors, a longer pipeline
route may be selected. These decisions may be made to reduce the
possibility of oil spills and their impact on fish and wildlife.

Location: In the United States, the SPM has been proposed with a
highly specialized function of unloading crude oil from VLCC's. To
accommodate such large draft vessels, deepwater sites are sought as
close to shore as possible to minimize underwater pipeline construction
costs. To reduce the chance of collision, SPM sites should not be in or
near regular shipping lanes. Desirable locations, where a vessel can
anchor sheltered from the weather, exist only in a few places around the
United States. Prevailing winds and oceanic currents will have to be
considered in siting a single point mooring to avoid locations where
there would be a high risk of an accidental oil spill coming ashore.

Design: With the need to service VLCC's, the selected deepwater
site will need ample space to allow manuevering of the large ships
including turn-around capability. To reduce the chance of an accidental
oil spill a highly reliable transfer system should be employed to keep
human error to a minimum. A sophisticated monitoring system, which not
only records unloading operations, but gives indications of possible
trouble sources should be incorporated into the design.

The pipeline from the single point mooring to the onshore oil
terminal will have to be buried to avoid possible rupture and oil leaks
from fishing gear, dragged anchors, etc. Automatic safety valves at the
mooring, at the oil terminal, and perhaps between those points will have
to be installed to minimize the effects of accidentally spilled oil.

114

Construction: With the need to lay a pipeline to shore, most of
the environmental impacts will arise from the dredging needed to bury
the pipeline. (Section 2.2.4) Dredging of pipeline trenches, especially
in coastal areas should be done in a manner which will minimize turbidity
and sedimentation (such as the employment of sediment screens and other
techniques). If pipeline trenches are dug through wetlands, excavated
material should normally be replaced in the trench instead of diked
along the sides where it can interrupt water flow and change circulation
patterns, salinity, temperature and other factors. Also, fill material
should be added incrementally where necessary, not all at once, in order
to keep the elevation above the pipeline the same as that of the
surrounding wetlands.

Operation; The major environmental problem in SPM and tanker
operation will be in meeting pollutant discharge standards on waste
disposal and oil discharge. Constant supervision and contact will have
to be maintained between the single point mooring buoy and the oil
tanker to ensure proper and safe transfer.

The possibility of tanker damage and oil spill are significantly
reduced if single point moorings can be situated where navigational
hazards (such as rock outcrops) are absent. Most oil spilled into water
initially floats at the water surface. Wind and water forces effectively
distribute spilled petroleum hydrocarbons into all components of the
marine and coastal environment, including the water column, sediments,
atmosphere, and the organisms present in the marine and coastal eco-
systems.

Wildlife that comes in contact with an oil spill can be harmed
or die from ingestion of petroleum, or can lose the insulating
capacity of their feathers or fur. Generally, fish are ableto
avoid the effects of an oil spill because they swim beneath it,
but aquatic birds present other problems. Some diving birds
that fully submerge are mostly unable to walk on land and are vir-
tually restricted to the aquatic medium. Oil spills have drastic
implications to oceanic birds which are found to the aquatic
medium.

In addition to direct kills of organisms, the major adverse environ-
mental effects of direct oil pollution of coastal waters are: (1)
disruption of physiological and behavioral patterns of feeding and
reproductive activities of aquatic species, (2) changes in physical and
chemical habitat, causing exclusion of species and reduction of
populations; and (3) stresses on the ecosystem from decomposition of
refinery effluents resulting in altered productivity, metabolism, system
structure and species diversity.

115

The effects of oil spills are complex, whether from tankers, SPM's,
platforms, or terminals. Some of the major components of fish and wild-
life species and habitats that are affected [32] follow:

1. Endangered Birds - The known and suspected coastal
habitats of the American Peregrine Falcon, Southern
Bald Eagle, and Osprey, and other birds identified
as sensitive in any seasons.

2. Migratory Waterbirds - Areas along the shore identified
as having significant concentrations of migratory
birds during the winter, spring, and fall seasons.

3. Shellfisheries - Areas along the shore identified as beds
for surf clams, bay scallops, northern hard clam, oyster
and others. Both commercial and sports harvesting
areas for these species in any seasons.

4. Coastal Finfish - A 25-mile strip of coastal waters
along the entire length of shore identified as
critical during the summer and fall seasons with
respect to the egg and icthyoplanktonic stages of
the scup, porgy, menhaden and other species.

5. Estuarine Finfish - Estuarine areas and sounds
identified as important areas for weakfish,
sea trout, whiting, striped bass and other

fish during the spring, summer, and fall seasons.

6. Wetlands - All marsh areas identified as
sensitive in any seasons.

7. Wildlife Refuges and Management Areas - All
national wildlife refuges, wildlife management
areas, wildlife areas, and natural areas
identified as critical in any seasons.

8. Beaches with High- Intensity Use - National
Recreation Areas including adjacent state and
municipal beaches identified as areas of high
intensity usage in any seasons.

9. Parks and Recreation Areas - The locations of
all state parks and national recreation areas
recorded as important in any seasons.

10. Offshore Dumpsites - The locations of offshore
ocean dumpsites recorded for any seasons.

116

Regulatory Factors:

SPM: A single point mooring system requires numerous federal
permits and certificates associated with the location of a facility in
navigable waters; dredge and fill; and pipelines. State and local
permits are also required for associated landfall facilities.

Typically an SPM will be associated with a "deep-water port" or
transshipment facility located outside the three mile (or marine league)
limit of state jurisdiction. These facilities are governed by
comprehensive federal legislation adopted by Congress as the Deep Water
Port Act of 1974.

The Department of Transportation is the lead agency in licensing
these facilities, including associated SPM systems. The Coast Guard
manages the program. The Act sets up an "adjacent state" identification
procedure and states identified through the procedure have statutory
rights to advise and comment on the licensing process.

Associated facilities located nearshore or inshore are subject to
the multiple jurisdictions described under "pipelines," (Section 2.2.4).
The Corps of Engineers, Materials Transportation Bureau* and EPA are the
primary agencies for the management of federal interests in construction
and operation of these facilities.

Tankers: The Coast Guard maintains a surveillance and enforcement
system for tanker operations in U.S. waters. These are defined in
considerable detail in the Code of Federal Regulations, Volume 33, Part
155, and Volume 46, Chapter 1. United States flag vessels and foreign
flag vessels in U.S. domestic trade are included under these provisions
if they exceed a threshhold of 150 tons.

Oil spills from tankers fall under the Comprehensive Oil Pollution
Liability and Compensation Act of 1975 which establishes a basis for
liability for owners and operators of tankers and sets specific maximum
amounts for liability.

Development Strategy

SPM's offer advantages over conventional deepwater port facilities.
SPM's minimize mooring forces, can be adapted to a wide range of water
depths, different bottom conditions and other varying environmental
considerations. The initial cost of construction and installation time
is considerably less than deepwater harbors or long piers. The need for
dredging and related spoil disposal activities are eliminated and SPM's

The FPC licenses interstate gas pipelines.

117

can be utilized in the distribution of refined products as well as crude
transfers.

One desirable feature of SPM's is they diminish tanker traffic
around port areas and confined harbors, where maneuverabili'ty may be
constrained. However, SPM's have been designed to work with the largest
tankers; smaller tankers still operate along the /coast and in industrial
ports. In some areas, such as along the west coaSt of the United States,
this trend is expected to grow rapidly when oil from the North Slope
is transported into ports in California.

Decisions about single point mooring systems are generally made
within two realms--the first relating to the whole transportation
strategy for offshore oil, and the second relating to national policy on
importation of oil .

An SPM operates solely as an oil transfer unit, however, the complete
system would involve a power unit for pumping, submarine pipeline,
landfall and a network of onshore pipelines, oil storage terminals and
at times, refineries. An SPM system as proposed by Seadock would
employ a number of SPM's connected to a complex of platforms by buried
pipes. Discharged cargo at an SPM would flow through a floating hose to
a buried submarine pipeline to a platform complex. From the platform,
booster pumps would move the crude to an onshore storage terminal. From
the storage terminal, the crude oil would be distributed by pipelines to
refineries.

SPM's connected to shore terminals, as currently proposed, are
primarily designed to handle imported crude oil. The approvals for
SPM's--which require extensive State and Federal reviews--are therefore
influenced by national policy toward reduction of dependence on imported
crude.

118

2.3 ONSHORE DEVELOPMENT PROJECTS

Planning onshore development calls for different industrial strategy
than offshore. Offshore is a high stakes game where huge investment is
required to back up each project proposal; it is private enterprise
operating in classic style where investments, risks, and the potential
for returns are all large. Onshore is different because it is a lengthy
process of solving an elaborate series of administrative hurdles imposed
by Fede»*al, state, regional and local authorities with relatively small
investments. Offshore investment involves only the oil companies and
major contractors while onshore investment also involves many small,
independent support companies, or vendors, who supply and service the
oil companies. Onshore activity is confusing as it includes a large
number of enterprises in a complex industrial structure, has great
investment flexibility, and actions of member industries are often
difficult to predict.

The onshore development projects presented in this section are:

2.3.1 Service Bases

2.3.2 Marine Repair and Maintenance

2.3.3 General Shore Support

2.3.4 Platform Fabrication Yards

2.3.5 Pipe-coating Yards

2.3.6 Oil Storage

119

2.3.1 Service Bases

The supply and support of offshore rigs and platforms is a vital
element in the effort to produce oil and gas in the marine environment.
Only a limited amount of the necessary supplies can be stockpiled
alongside the rig or platform during all phases of operation. It is
essential that the supply line from shore to the offshore drilling area
be maintained in an orderly and timely manner; an ineffective supply
system can be very costly as any downtime due to lack of supplies and
equipment add unnecessarily to the overall drilling costs.

Service bases (or staging areas) are the logistical links between
offshore and onshore activities. The main activity of a service base is
the transfer of materials and crew members required to operate rigs and
platforms between land and offshore operations. Service bases contain
berths for supply boats and crew boats, dock space for loading and
unloading, warehouses, open storage areas, office space, trucking and
freighting facilities, and a machine shop. Optional facilities may
include a mineral-processing area (for drilling-mud preparation), an
offshore workover area (for reworking of producing wells), and possibly
a helicopter landing area for personnel transport. Numerous additional
facilities are required to support the central staging area as an effective
and efficient base of operations. These operations include food/catering
establishments, marine equipment distributions, and repair shops.

Service bases are sometimes set up by the oil companies for their
own use, or they may be built and operated by companies which specialize
in serving offshore operations and under contract to the oil companies
(Figure 27). Support bases have traditionally been established by
drilling-mud supply companies (known as "mud companies"). More recently,
specialized companies have evolved whose main function is the establish-
ment of service bases, such as the Aberdeen Service Company Ltd., in
Scotland. Some major oil companies, since they either own or have rigs
on extended contract, prefer to carry out their own operations onshore.
Other oil companies find that a base run on a large scale by another
company provides an attractive alternative due to the flexibility it
allows.

Description

Service-base components will vary depending on the size and rate of

production of offshore resources. Requirements are also a function of

available community and industrial infrastructures. In frontier areas,
service bases may be largely self-contained in rural environments such

as Alaska; or may be a new component to a developed waterfront port in
east coast locations.

120

Figure 27. Service base* - project implementation schedule.

INVESTMENT COMMITMENTS:

YEARS •••

PERMIT ACQUISITIONS:

Site Purchase
Site Option(s) Taken

Start of
Construction

^ Begin Use
^ of Base

Acquisition of Use and
Location Permits

Operating Permits

Preconstruction Permits
(Includes EIS)

* Note that this schedule applies to permanent service bases only.

The comprehensive service base contains the following minimal
components:

1. Sheltered deepwater harbor

2. Adjacent flat land for open storage

3. Wharf or pier space

4. Warehousing

5. Tanks for fuel storage

5. Silos for drilling mud and cement

7. Administrative offices

8. Heliport

9. Supply vessel fleet (see Section 2.3.2)

10. Cranes and loading equipment

11. Space for company dispatchers and communications

equipment

121

Optional components include:

1. Open storage for coated submarine pipe

2. Open storage for anchors and chains

3. Machine shops, repair, maintenance and

welding facilities

(A site plan of a new permanent supply base in Lerwick, the Shetland
Islands, is reproduced in Figure 28).

An onshore support base will also need an area set aside for a
mineral-processing plant, and space for vessel repair and maintenance.
The former is required to prepare drilling mud, an essential component
of all drilling operations. The basic drilling-mud composition tailored
to meet specific down-hole requirements is prepared at the plant,
although it may be slightly altered by the drilling-mud engineer on
s i te .

Back-up services might include [34]:

1. Specialized drilling services

2. Engineering services (repairs to equipment

and small fabrication)

3. Inspection services

4. Diving (underwater inspection and

maintenance)

5. Catering services

6. Air services

7. Freight handling, customs documentation, etc.

8. Agents of supply boats, tugs, etc.

9. Dredging and harbor works

10. Communications

11. Secretarial services

12. Emergency medical services

An important distinction is to be made between temporary and
permanent service bases. During exploration and exploratory drilling,
only temporary facilities are developed. Temporary service bases are
comparatively small operations, and the limited acreage (5 to 10 acres)
which they use is usually leased on a short-term basis. Public port
facilities already in operation are often used during the exploratory
phase.

After a commercial find has been located, land for a permanent base
(usually 50 to 100 acres) will be purchased or leased on a long-term
basis (more than one year). (Figure 27 is for permanent service bases.)
During field development, service bases supply essentially the same
types of goods and services required during exploratory drilling.
However, the scale and intensity of support services increases signifi-
cantly for two reasons. First, as many as 60 wells can be drilled from

122

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each platform which increases the number of personnel and supplies
needed. Second, success in a portion of a basin stimulates increased
exploratory activity by other lease-holding companies. A permanent base
contains more extensive and sophisticated facilities than a temporary
base in order to sustain the increased volume of supply-vessel traffic
which results from the escalated level of offshore activity.

Site Requirements

A site for a shore base to support offshore oil or gas activity
must be selected with care, so as to minimize the risk of delay and to
avoid increased costs to offshore operations. Nine site requirements
are commonly investigated to determine a location for a permanent service
base [34]:

1. Proximity to offshore oil or gas activity

2. Existence of previous bases

3. A sheltered harbor of suitable size and draft with

available capacity

4. An adequate waterfront site with contiguous back-up lands

5. Suitable airport/heliport

6. Adequate roads

7. Proximity to an established community

8. Temporary base site

9. Other factors

1. Proximity to offshore activity: This requirement reduces
the running time required for boats to ferry supplies from the
service base to the offshore installations. Proximity is criti-
cal because good weather conditions may last for only short
periods of time and because the operation of supply boats is

the greatest operating expense of a supply base.

2. Existence of previous bases: When a company has a permanent
base in the general area of a new lease, it will either operate out of
this base (rather than build a new one) or set up a satellite base for
the small, day-to-day logistical activities and use the permanent base
for transporting the bigger supplies and equipment.

The decisions to establish a temporary base that is nearer to the
locus of offshore activity than an existing permanent base affects space
requirements for storing and loading supplies, as well as the volume of
boat and helicopter traffic.

New facilities to service a rig operating within 100 miles of a
permanent service base are unlikely. If a rig is between 100 and 150
miles away from a permanent service base, a temporary base is likely to

124

be set up at least for changing crews, either by boat or helicopter, and
for supplying small items not peculiar to the drilling industry; larger
supplies, such as casing, mud, and cement will be supplied from the
permanent base. Beyond 150 miles the creation of an independent base
becomes increasingly probable [26].

3. Sheltered harbor: The availability of adequate sheltered harbors
in the general area of offshore leases or proposed areas of activity is a
major factor in locating service bases. The harbor must permit the load-
ing and sheltering of supply vessels whose size, draft, and capacity

are three important considerations. At a minimum, the harbor should have
the physical dimensions to allow the maneuvering, anchoring, and berthing
of a large number of offshore supply boats, ocean-going barges, and other
vessels supplying the base.

Since many supply vessels may sit idle between trips or may be
loaded and have to wait for the weather to improve before going to sea,
the capacity of a harbor is also significant. Ideally, all vessels
should be able to moor at shoreside. However, if sufficient dock spaces
are not available for this, capacity must be available to moor the sup-
ply vessels two or three abreast at shoreside, or space must be available
to safely anchor them in the harbor (20 to 30 feet depth).

4. Waterfront site: Service-base operation efficiency is measured
in terms of turnaround time, the time required by a vessel to dock, to
load all of the supplies requested, and to start back to the offshore
operations. It is, therefore, desirable that oil service bases be set
apart from the plants and boats of the fishing industry and other users
of the waterways to avoid delays caused by congestion with other vessels
and conflicting use of waterfront facilities.

The location within the harbor also requires large quantities of
flat land, or back-up land, adjacent to the dock locations on the
waterfront. At dockside there are minimum requirements for staging
areas, silos, warehouses, storage tanks, and open storage, tlowever,
the large quantities of pipe goods handled and stored also require
flat areas. If flat land is unavailable, it is, of course, possible
to cut and fill during the construction of the service base facility.

5. Airport-heliport: In areas where road and rail connections
are undeveloped, it is essential that a service base be connected by
road to an airport, preferably one with scheduled main-line service and
wiht facilities to handle heavy cargo services and helicopter operations
for offshore areas. The principal function of an airport serving off-
shore oil operations is the transport of crews to and from the offshore
facilities. However, the marine service base also requires the services
of the airport and/or heliport: (1) to permit the rotation of the supply-
boat crews, (2) to transport emergency supplies and service personnel

125

via helicopter to offshore locations, (3) to receive emergency supplies
for shipment by supply boats to offshore facilities, (4) to transport
sick or injured workers to major medical facilities, and (5) to enable
administrative and technical personnel from both industry and government
to have ready access to the service base [26].

6. Roads: Adequate roads between the airport and the service
base are essential, since there will undoubtedly be occasions when large
quantities of tubular goods and other heavy materials will be transported
between the airport and the service base. Similar requirements will be
demanded within the service base where heavy loads will be constantly
shuttled to and from storage areas. Aside from these basic road require-
ments, an adequate road between the service base and the adjacent community
will also be needed.

7. Proximity to an established community: A community can
provide the service base with elements essential to its operation that
would otherwise have to be brought in or constructed, including labor
force, utilities, and local supplies. These factors are discussed in
the section on Community Effects.

8. Temporary base site: During the exploration phase, the number
of temporary bases and their distribution among available ports in a
region will depend on several factors: the number and distribution of
lease holdings, the distance from the port to the leased tracts, and the
location of existing bases operated by lease-holding companies.

The location of bases established during the exploration phase may
prove convenient for the development phase as well. However, if the oil
field is located a considerable distance from the temporary base used
during exploration, the permanent base may be set up in a more convenient
location. The incentive to make this move increases if the supply haul
is long, if the field is large, or if there are a number of fields being
developed. The decision to move may be less complicated for those
companies which have not set up semi -permanent facilities during explora-
tion. Companies with short-term contracts for mobile rigs, berth space,
and back-up land are more likely to move their bases as the offshore
exploration proves successful.

Temporary bases are often set up under less than ideal conditions,
since the activity level in the preliminary phase of offshore exploration
is relatively low and the future development potential uncertain.
Hence, they may have inherent limitations, such as insufficient acreage
for expansion, or insufficient linear dock space to support projected
future levels of vessel activity brought about by accelerated OCS develop-
ment. If such is the case, the company may have to look elsewhere for a
site for a permanent base even if the original base site is sufficient
in all other respects. Ability to expand the initial site is therefore

126

an important concern in locating the temporary base. If a commercial
find is discovered by the same company which used the temporary base,
the permanent base will probably be set up in the same port.

It should be noted that an early commitment to a service base does
not necessarily commit the area to other facilities demanded during
subsequent OCS development stages, such as terminals or processing
plants. Although industrial incentives lean toward locating facilities
together, there is little evidence to suggest that industry now situates
facilities to support early OCS development stages (such as service
bases) with later joint facilities in mind.

9. Other factors: Experience in the Scottish sector of the North
Sea has indicated that, despite disadvantages in location, some communities
have attracted service base activity through a willingness to satisfy
industry demands in a timely manner [34]. However, in other instances,
despite the presence of efficient comprehensive service base facilities
open to all, on contract or otherwise, independent control of service
base operations may be highly valued by a particular operating company.

Construction/ Installation

Construction of a service base involves shorefront preparation. A
service base will locate where shorefront port facilities meeting water
depth requirements are already available. This minimizes costly start-
up time spent in lengthy permit procedures for dredge and fill, zoning,
and other procedural requirements. Under certain conditions, dredging
and filling may be required either as the base develops or for maintenance
purposes. The base will evolve in size and services concurrently with
offshore operation growth and field development.

Construction of the base is a relatively rapid process; however,
the base will probably not be completed during a single construction
phase. Components of the service base will be constructed in response
to offshore service demands which include the size and age of the field,
new discoveries, and other factors. The construction process for these
facilities should be of limited environmental concern after the site has
been prepared in accordance with environmental safeguards. As the
service base responds to rapidly evolving offshore needs, the availability
of a site ready for construction is important to the supply-base contractors,

Operations

The central staging area is the heart of the exploration, development
and production activities for offshore petroleum. Figure 29 shows the_
movement of persons, equipment, and materials through the central staging
area to and from the mineral -processing area, workover areaj offshore

127

operations, and onshore support functions. An example of the types and
quantities of goods required to support each exploratory well are listed
below [34]:

10.000' Well 14.000' Hell

-__

168

467

700

275

300

233

350

1,580

2,400

2.500

3,750

30" Casing

20" Casing

13 3/8" Casing

9 5/8" Casing

Bentonite

Cement

Barite

Miscellaneous consumables

Fuel (including supply vessel fuel)

Drill Water

TOTAL 5,193 tons 7,811 tons

Although the level of activity in a few service industries will
peak during the development phase and taper off during the production
phase, there will most likely be an increasing market for maintenance
services at the platforms and other facilities. While the relative size
and activity of component industries oscillates during the life of the
field, all service bases have common components.

Community Effects

A service base is characterized by the following attributes of
interest to shoreline communities: major source of employment for both
construction and operation, potential tax base, medium-size parcel of
land along the waterfront in a developed harbor and access to all
transportation systems.

Employment: Assuming new facilities are required for a permanent
support base, one study suggested an average of 20 and a maximum of 90
employees would be required during a one-year construction period. This
level of activity would be a measurable generator of income in a small
community [28]. A temporary base, by contrast, will use or modify
existing structures and facilities to minimize investment, thus providing
minimal construction employment.

During the exploration phase a temporary service base involving
minimal investments would be located in a frontier area. The total

128

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number of jobs in a temporary base in Florida was 32 jobs, 12 of which
were filled by local residents [26].

Employment at a service base varies with the stage of field develop-
ment as shown below. All figures are per platform [26].

Personnel Required During Offshore Field Phases

Facility

Exploratory
Drilling

Production
Drilling

Production

Supply boat
Crew boat
Helicopter
Wharf & warehouse

30-36
6
3

4-6

30-36
6
3
9

3
3

Total

42-

■54

48-54

Local personnel

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18-22

Total salary
(17,000 avg.)

$734:

,000

$816,000

$374,000

Induced Effects: Local employment and temporary residents will
bring additional funds into the community, stimulating commercial
activity. Most jobs require semi-skilled help which should be available
in any developed port. This income will have a multiplier effect on the
economy of the community. In addition, physical facilities will add to
the tax base. If the port already has commercial services, service
demands based on anticipated OCS development should not burden existing
capabilities.

The average wage rate is likely to be higher than that for traditional
waterfront employment. Thus, workers may be attracted away from other
commercial enterprises, such as fishing. The number of local people
employed in the service base is almost constant, the variable being non-
local labor. Therefore, the individuals diverted from existing employment
sources would not return to the traditional activities for the duration
of the field's productivity, a span of at least 20 years.

Effects on Living Resources

A service base has the following characteristics of particular
concern to fish and wildlife: (1) piers and bulkheads; (2) channels and

130

turning basins; and (3) filling of wetlands, which must be considered
during the location, design, construction and operation of the facility.

Location: The ecological problems related to service bases are
primarily a result of the necessity to situate the facility on the
waterfront. With crew boats and supply boats constituting the main link
between offshore needs and onshore supply, sponsors desire a sheltered
channel or harbor allowing efficient loading and unloading. Locations at
the mouth of bays and estuaries will aid in the flushing and dispersion
of silts stirred by boat propellers and petroleum discharges from engines.
Channels and harbors that require little initial or maintenance dredging
should be considered as first choices for the locations of service
bases.

Design: All possible attempts should be made to locate service
bases on existing waterfront property to avoid the loss of fish and
wildlife habitat through filling of wetlands. The need for navigable
channels and turning basins will cause dredging problems of turbidity
and sedimentation, which may lead to the smothering of clams, corals,
and other sessile organisms. Channels should be designed to limit the
amount of initial or maintenance dredging, i.e., the channel route
usually should be the shortest distance to the service base. However,
the type of substrate must also be considered. Loose, unconsolidated
material requires more frequent maintenance dredging.

Construction: With the construction of a bulkhead to service
boats, shores are often dredged to create the berth area and to obtain
fill to place behind the bulkhead. Although inexpensive and quick,
this method alters the natural configuration of the shoreline and robs
areas downshore of needed sand by interrupting littoral drift. Addi-
tionally, solid-fill structures tend to intercept, divert, and disperse
water currents in directions where previously they had not gone or
cause them to become diffused through mixing with other currents.
This diversion may decrease available food supplies and change water
parameters, such as salinity, oxygen, etc., leading to a significantly
altered fish and wildlife habitat. If wetlands are filled, there will
be a loss of breeding/feeding grounds and generally productive areas
for fish and wildlife. Construction of open pile piers and floats
will greatly reduce the above effects.

Operation: Regarding service-boat traffic between offshore rigs
and the service base, the sponsor will find it necessary to ensure that
accidental and illicit discharges be kept to a minimum. All boats
should be rigidly inspected to prevent any unnecessary oil and grease
from entering the water. Also, transfer of drilling mud and other
compounds from the marine terminal to the boat should be executed
according to pre-established safety procedures to reduce accidents
to workmen and to the environment.

131

Regulatory Factors

Service bases are likely to be located in existing harbor facilities
where state and local certifications or permits may not be required or,
if required, are straightforward. Creation of a new harbor facility,
however, will entail the process of state and local approvals. Because
service bases nearly always require channel modification or maintenance,
Federal dredge and fill permits are an important consideration in site selection.

Federal Role: The Corps of Engineers issues dredge and fill permits
under the authority of Section 10 of the Rivers and Harbors Act of 1899,
Section 404 of the Water Pollution Control Act Amendments of 1972, and
regulations that they issued July 25, 1975, in Volume 40 of the Federal
Register, pages 31320 et seq. The Fish and Wildlife Service must be
consulted before the permit is issued. In addition to commenting on
technical questions related to wildlife and habitat conservation, FWS
recommends mitigation measures. The District Engineer issues the permit
unless timely objections are filed by interested parties, including the
FWS. If substantial objections are filed the decision is referred to the
Division Engineer. If the FWS maintains its objection, the decision to
issue the permit must be made in Washington by the Secretary of the Army
after consultation with the Fish and Wildlife Service through the
Secretary of the Interior. Fish and Wildlife Procedures are set forth
in the Navigable Waters Handbook of the Service.

Development Strategy

The oil or drilling company's (and suppliers') strategy for
selecting a location for a support base centers on finding an adequate
site which can be rapidly developed when needed to support offshore
operations. The background investigations to determine a specific
strategy in a frontier area are initiated by a port survey. After the
survey is completed and analyzed, the variables considered for
selecting the initial, temporary site might include available facilities,
community attitudes, costs , long-term development potential, and the site
requirements discussed earlier in this section.

If any developed ports lie within approximately 200 miles of an
offshore field, it is unlikely that an undeveloped harbor would be
considered. Delays caused by required waterfront and harbor site
preparation in an undeveloped area will be bypassed. Delaying factors
to be avoided may include procedural requirements, site preparation
requirements, or land availability. The two pressures causing a company
to select an undeveloped area over developed alternatives are: (1) the
undeveloped harbor is significantly closer to the field, (2) or the
political posture of the community at the developed harbor (as expressed
through zoning ordinances, land use plans, and policies, etc.) is negative
to the proposed development.

132

In a potential frontier region that contains ample ports, e.g., New
England, each (major) drilling company will identify two or three poten-
tial ports which can meet the needs for setting up a temporary base of
operations. There is uncertainty associated with the offshore leasing
process and companies are not sure which tracts (if any) they will own
an interest in until after the sale. Therefore, neither options nor
acquisitions are likely until after the lease sale.

Recognizing the uncertainty faced by the oil companies, a mud
company or service company will sometimes establish a base in a port
that is convenient to the lease area and that possesses the necessary
site requirements; then the mud company or service company may attempt to
make an arrangement with one or more oil companies by offering free dock
space in exchange for the contract for mud and/or drilling fluids. This
strategy may result in several oil companies operating out of a single
base. Since the service industry is so highly competitive, three or
four such bases may possibly be set up in different ports.

After a temporary base is established, the company will probably
continue to develop the site into a permanent base, if offshore
discoveries merit increases in onshore development. The desire to stay
in the same location reflects industrial inertia fostered by a
familiarity with the capabilities and limitations of the temporary site.
If another site were selected, additional unproductive efforts such as
altering the supply system associated with transportation, hiring a new
labor force, and closing down the temporary base would increase present
costs and would offer returns only in the future. The only two possible
reasons for relocating the supply base are: (1) need for additional
land space or waterfront for significantly increased activity, or (2)
selection of a site closer to the offshore leases. The latter cause is a
real possibility under the frontier lease system, as large areas are
leased simultaneously and the possibility of discovery exists in each
leased tract. Companies, however, are aware which tracts are considered
most likely and, therefore, attempt to minimize the necessity for re-
locating their supply base by selecting a site close to the "best"
tracts.

133

2.3.2 Marine Repair and Maintenance

The petroleum industry uses many types of vessels in offshore
activities. These vessels may be owned by the oil companies, by support-
ing companies, or by independent companies whose business is making
necessary support vessels available on a charge basis (see Figure 30).
A partial list of these vessels is given in Table 12. Examples of
typical support vessels built by a major supplier are profiled in Figure
31.

Figure 30. Marine repair and maintenance - project implementation schedule.

INVESTMENT COMMITMENTS:

YEARS •••

Site Purchase

Site Option(s) Taken

Start of
Construction

„ Begin Yard
Operations

Acquisition of Use and
Location Permits

Operating Permits

PERMIT ACQUISITIONS:

Preconstruction Permits
(Includes EIS)

Shipyards, or marine repair and maintenance facilities, are used to
keep these vessels in good operating condition. The industry is not a
single firm or specific facility, but rather a range of firms that are
used to repair and maintain the wide variety of OCS-related vessels and
equipment. These firms already exist in many ports to maintain all
types of commercial marine vessels, and the development of OCS-related
activities will be an additional source of work and income to these
firms. Although OCS activity may stimulate additional firms, there is
a greater likelihood for existing firms to expand.

134

Table 12. Some Vessels Used in Offshore Petroleum
Recovery Activities

Type of Vessel Description

Crew For personnel transport; high speed boats

Utility/supply General maintenance and movement of

light-weight equipment and cargo.

Supply For transport of bulk cargo.

Utility Maintenance and general work.

Tug Light to heavy towing.

Tug-supply Moderate towing and transport of

portable equipment and cargo.

Crew/utility For personnel transfer and general work.

Crew/supply For transfer of personnel and equipment.

Existing boatyards in the adjacent onshore region may experience
increased activity for repair and maintenance of the fleet of vessels
associated with offshore drilling. An increased level of business can
also be expected for welding and machine shops, caterers, and transport
companies.

Most of the United States onshore support operations are located on

or near the Gulf of Mexico because the OCS business started there. However,

this location is not a constraint in supplying equipment for OCS

utilization on a worldwide basis. For example, there are ten shipyards

in the United States which have the capability to construct and service

offshore mobile exploratory rigs. Five shipyards are located in Texas,

at Beaumont, Brownsville, Orange, Galveston, and Ingleside; one each in

New Orleans, Mobile, and Vicksburg; and two on the Pacific Coast at

Takoma and Oakland. The scale of the rig-building industry is indicated

by the fact that in mid-1975, the value of rigs under construction

exceeded $1.0 billion. Shipyards for the construction and maintenance

of support craft, including survey boats, are likewise clustered around

the Gulf Coast. , .^

1 3b

Figure 31. Characteristics of typical
(Source: Reference 35).

support vessels

65 FOOT CLASS

M/V Aunes-Crewboat

Specifications:

Horsepower: 850

Dimensions: 65' x 17' x 10'

Speed 26 MPH

Fuel Capacity: 950 Gals

Passengers 34

110 FOOT CLASS

M/V Bay Seahorse-Production/Utility Vessel

Specifications;

Horsepower: 1936

Dimensions 1 10' x 25' x 11'

Speed: 16 MPH

Fuel Capacity: 1 3,000 Gals

Passengers: 34

100 FOOT CLASS

M/V Canadian Seahorse-Crewboat

Specifications.

Horsepower: 2050

Dimensions: 90' x 21' x 7.5'

Speed 25 MPH

Fuel Capacity 2,500 Gals

Passengers: 44

8000 HORSEPOWER CLASS

M/V Atlantic SeahorseTug/Supply Vessel

Specifications

Horsepower 7568

Dimensions: 210' x 40' x 17.5'

Speed 16 MPH

Fuel Capacity: 150,000 Gals

Below Deck Mud Capacity: 4,000 Cu. Ft

Chain Lockers 8000' of 2-3/4" Chain

Towing/Anchor Handling Winch: 350,000 Lb Single Line Pull

Bow Thruster 500 Horsepower Producing 10,000 Lbs Thrust

165 FOOT CLASS

M/V Bengal Seahorse-Supply Vessel

Specifications:

Horsepower: 2550

Dimensions: 166' X 38' X 13'

Speed 14 MPH

Fuel Capacity: 45,000 Gals.

Below Deck Mud Capacity: 2,000 Cu. Ft.

136

It is difficult to predict the ultimate extent of expansion of
various shipyards and fabricating yards associated with the frontier OCS
areas. There are a variety of factors that could prompt a builder to
expand from the Gulf Coast to the East and West Coasts:

1. degree of success of oil and gas discovery;

2. backlog of orders in his current facilities;

3. company forecast of new business a facility
could generate and its profitability; and

4. zoning regulations and environmental restrictions
that may preclude timely development of a

new facility.

For the next few years a wholesale shift of construction facili-
ties to the OCS frontier area is not anticipated. However, if these
new zones are productive, many companies will consider moving construc-
tion facilities to the areas during the mid-1 980' s.

Description

The diversity and quantity of requirements for marine repair and
maintenance facilities increase as the number of vessels increases. Two
or three vessels are associated with pre-lease drilling; more substantial
needs appear in the exploratory phase, and even more extensive needs are
indicated by a mature field with production workover phases.

A repair and maintenance yard (or facilities) is located on the
waterfront in a developed harbor. The equipment and layout of the yard
reflect the needs of the port and can vary considerably. A large facility
servicing a major port might include pipe, plate, and welding shops,
storage buildings, dockside ship service facilities, and a dry dock.
These facilities would be situated within the site to allow docked
vessels to be easily serviced.

Dry docks are needed for repairs on the hull, shafts, and propellers.
The majority of boat repairs can be made while the vessel is in the
water. If possible, boats are "hauled out" only in cases of necessary
bottom work or for periodic Coast Guard certification and licensing
inspections.

Marine repair and maintenance facilities are located in developed
harbors in response to demand associated with initial commercial harbor
users. Existing facilities will be used initially unless a major field
is found in a frontier area where no developed ports are available
within an appropriate distance. As the field is explored and developed

137

the gradual buildup in demand for this service by OCS-related com-
panies means an increase in business for enterprises already support-
ing fish or commercial shipping concerns. These repair and mainte-
nance businesses will expand staff, inventories, and work space to
accommodate the new vessels.

The initial fleet of boats serving a frontier area may well be
contracted from an established company in the Gulf Coast area. A boat-
chartering company may decide to locate a branch office in a harbor near
the frontier area if the demand for vessels increases. A simple site
might include berths, crew quarters, and office space to operate the
chartering service. Repair and maintenance services would be sought
from nearby established facilities. Or the company, anticipating
continued increases in offshore development, may establish a small
repair and maintenance area to handle most work on its own boats.

Alternatively, established shipyards may develop specialized
repair yards for petroleum-industry work boats, probably adjacent
to their larger operations. Along the Gulf Coast and in the
North Sea skilled mechanics from existing shipyards or related
heavy industry have opened small independent repair and mainte-
nance service operations, catering to specialized oil and gas
industry work [26].

Construction/Installation

Increased OCS activity will not be expressed in major construction
at new sites, but rather in less significant construction to expand
existing wharf and support areas. If a large number of additional
vessels require service, additional entrepreneurs may be attracted.
However, they would not invest the capital necessary to build a dry dock
or other major facilities; rather they would obtain or purchase some_
dock space and would compete by performing specialized aspects of main-
tenance. The only exception to this process would be investment by a
charter service for oil-industry vessels. If a large field with diversi-
fied activities and needs were predicted, such a charter service might
construct a new major repair and maintenance facility primarily to
service its own vessels.

Operations

Basically, two types of maintenance repairs are peformed: mechanical
and electronic. This work is done either at dockside or with some
degree of "haul out" ranging from the use of a derrick and flotation
barge to the use of a dry dock. Mechanical repairs are made on the
major and auxiliary drive trains, diesel engines (Caterpillar, Alco),
reduction gears (Caterpillar, Lufkin), shafts, and wheels. Mechanical
repairs also include repairs to the vessel superstructure, such as

138

welding, scraping, painting and associated work on the boat body and
compartments, and repairs of auxiliary mechanisms such as generators,
pumps, winches, anchorage gear, etc. Electronic repairs are made on
instruments, such as radios, radar, LORAN, and fathometers [26]. Large
vessels, such as pipe-laying barges, drill ships, semi-submersibles, and
other large OCS-related carriers will be serviced of necessity in major
shipyards. These large shipyard facilities are involved with construction
and conversion of vessels, as well as with repair and maintenance. Here
the largest boats can find dry dock facilities and most other services
normally required by such vessels. The OCS-related vessels will merely
be a new client for existing businesses.

The most likely sources of service for these vessels is at those
harbors that customarily service larger commercial fishing vessels. The
facilities used by commercial fishermen normally have sufficient "haul
out" and repair capability [26].

Community Effects

Marine repair and maintenance facilities in developed harbors may
expand if warranted by increased demand for services from OCS-related
vessels. Expansion may include additional waterfront, but it is more
likely to be reflected in new equipment, increased employment, and
expanded service facilities such as machine shops.

Employment: Employment in existing yards will increase if the firms
are to provide the additional service. Labor requirements range from
skilled and specialized capabilities for repairing electronic gear to
semi-skilled and unskilled jobs of scraping hulls and other heavy labor.
Some skilled positions may attract new workers from other areas, especially
if those skills are not readily available in the regional labor pool.

Induced Effects: Expansion should require only a minor increase in
the demand for services. The greatest effects would involve sewage and
solid waste disposal. However, these services may already be provided
within the repair yard. Any increased development because of increased
employment should be minimal. Expansion of an existing enterprise under
these circumstances is desirable for a community because it costs little
in additional services; but it increases the tax base, employs people in
categories of potential chronic unemployment, and helps insure the
survival of the businesses for a few years.

Effects on Living Resources

A marine repair and maintenance facility has the following character-
istics of particular concern to fish and wildlife: (1) piers and bulk-
heads; (2) channels and turning basins; (3) dry docks; and (4) filling

139

of wetlands. These must be considered during the location, design,
construction and operation of the facility.

Location: With ships, boats, and drilling rigs needing mainte-
nance on a regular schedule and occasionally needing emergency repairs,
a facility is usually located in a sheltered channel or harbor. This
allows easy access for vessels and gives the protection from the
open ocean necessary during repairs. Location at the mouths of bays
and estuaries would aid the flusing and dispersion of silts stirred by
boat and mobile-rig propellers and of petroleum discharges from engines.
Channels and harbors that require little initial and maintenance dredging
should be considered as the best choices for the location of facilities.

Design: Repair and maintenance facilities should be placed on
existing waterfront property to reduce adverse effects on fish and
wildlife. This would avoid the loss of fish and wildlife habitat
by the filling of wetlands.

The need for dredging navigable channels and a turning basis will
cause problems of turbidity and sedimentation, which may lead to the
smothering of clams, corals, and other organisms. Oxygen depletion is
also associated with dredging. Channels should be designed to limit the
amount of initial and maintenance dredging. The channel route should be
the shortest distance to the facility for dredging with minimum disruption
of fish and wildlife habitat. Also to be considered is the type of
bottom material, with loose, unconsolidated material requiring maintenance
dredging more often.

Floating dry docks should be utilized where feasible instead of
excavated dry docks. Floating dry docks reduce the need for excavating
wetlands; such excavation leads to reduced aquatic productivity and loss
of breeding/rearing areas.

Construction: Open pile piers and floats should be built instead
of sheet steel bulkheads. In the construction of steel bulkheads for
the repair of boats, shores are often dredged to create a berth and to
obtain fill to place behind the bulkhead. This alters the natural
configuration of the shoreline and robs areas down the shore of needed
sand by interrupting littoral drift. In addition, solid-fill structures
tend to intercept, divert, and disperse water currents. This diversion
decreases available food supply and changes water parameters, such as
salinity, oxygen, etc., leading to a significantly altered fish and
wildlife habitat.

Operation: When repairs are being conducted on ships and rigs in
the facility, all vessels should be inspected to prevent any unnecessary
oil and grease losses. Vacuum trucks and other skimming devices should

140

be employed to remove any collected oil. Any damaged vessels that
transport petroleum products should have oil booms placed around them to
contain discharges into the water during repairs.

Regulatory Factors

Marine repair and maintenance facilities are likely to be located
in existing harbor facilities, where state and local certifications or
permits may not be required, or if required are straightforward. Creation
of a new harbor facility, however, will entail the-process of state' and
local appovals briefly outlined in Section 2.1.3. Because these harbor
facilities usually require channel modification or maintenance. Federal
dredge and fill permits are an important consideration in site selection.

Federal Role: The Corps of Engineers issues dredge and fill permits
under the authority of Section 10 of the Rivers and Harbors Act of 1899,
Section 404 of the Water Pollution Control Act Amendments of 1972, and
regulations that they issued July 25, 1975, in Volume 40 of the Federal
Register, pages 31320 et seq. The Fish and Wildlife Service must be
consulted before the permit is issued. In addition to commenting on
technical questons related to wildlife and habitat conservation, FWS
recommends mitigation measures. The District Engineer issues the permit
unless the Regional Director of the FWS objects. An FWS objection
requires the permit decision to be made in Washington after consultation
between the Corps and the Department of the Interior.

Other Federal agencies may also comment on these applications.
Their objections result in review by the Division Engineer of the
application who either directs the District Engineer to issue the permit
or recommends denial. EPA theoretically has a veto in the process, but
the regulations under which a veto would be exercised have yet to be
promulgated.

Development Strategy

The strategy of marine repair and maintenance yards involves
augmenting existing facilities to provide prompt service for OCS-related
vessels. The development of this capability is a variable mixture of
expanding existing businesses and initiating new businesses, especially
for some of the specialized vessel needs. In harbors where extensive
capability already exists, such as Long Beach and San Diego on the west
coast. Mobile on the Gulf, and Gloucester in the northeast, little
additional development should be anticipated. The less the existing
port capability, given a constant resource size, the greater would be
the required repair and maintenance development.

In addition, the repair and maintenance industry will expand in
direct response to the intensity of offshore activity.

141

2.3.3 General Shore Support

Independent companies are contracted by the offshore petroleum "
industry to provide a wide variety of specialized services. These
companies are called general shore support or ancillary services. These
companies are usually small and specialized. They typically require
limited space and equipment, and are a potential for local employment
(see Figure 32). One study lists more than 120 companies in this
category [19].

Figure 32. General shore support - project implementation schedule.

INVESTMENT COMMITMENTS:

Site Purchase
Site Option(s), Taken

Start of
Construction

YEARS"*"

Begin

Support

Operations

PERMIT ACQUISITIONS:

Acquisition of Use and
Location Permits

Operating Permits

Preconstruction Permits
(Includes EIS)

General shore support includes all specialized OCS-support companies
not included in Section 2.3.1 (Service Bases) and Section 2.3.2 (Marine
Repair and Maintenance). The combination of enterprises described in
these three sections (2.3.1, 2.3.2, and 2.3.3) would include all the
onshore industries which support and service OCS facilities on a day-to-
day basis. These firms may also serve other onshore facilities such as
platform fabrication yards, natural gas processing plants, and refineries.
For some firms, such as a catering service, supporting offshore activities
may be one of many contracts; other businesses, such as mud suppliers,
serve only the petroleum industry.

142

Description

Lists of major support companies have been presented in several
studies (Table 13). Most of these companies lease existing commercial
space in frontier area harbors. They cluster together at the same
harbors as support bases. Petroleum companies coordinate storage and
shipment of supplies to offshore facilities. If a major new shore
support base is constructed, many general support firms could lease
space within the base. This locational relationship offers the most
cost-effective operation. In developed harbors, where the service base
uses existing facilities, general shore support companies will rent
space near the base.

Table 13. Major OCS Support Companies and Average Employment Figures
(Source: Reference 28)

Company

Average Employment

Mud Supplier (drilling mud)

Wireline Company (for drilling)

Gas Lift Company

Logging and Perforating Company (testing)

Welding Shop

Rental Tool Company

Fishing Tool Company

Wellhead Equipment Company

Machine Shop

Trucking Firm

Cementing Company (cement for drilling)

Supply Store

Downhole Equipment Company

Other (includes onshore catering support)

Total Employment

260

Each company is characterized by small labor requirements, using
small to medium-sized equipment and being physically indistinguishable
from other marine support activities on the waterfront. General shore
support companies can be placed in one of three groups. The first
group has a shorefront headquarters, but works primarily offshore.
Companies in this group, such as a diving service, use their onshore
base for equipment repair and administration.

143

The main function of the second group of companies is to assemble
or modify products onshore for use in offshore facilities. This diverse
grouping including catering services, machine shops, and mud suppliers,
require more onshore space for administration, production, receiving and
shipping.

The third grouping includes those firms which do not process
products, but rather assemble, store and ship items offshore when needed.
These companies, including the supply store and rental tool company,
require warehouse space.

Site Requirements

For many companies, such as a diving service, a waterfront location
with wharf and waterfront space is required. Other companies, such as a
rental tool company, can merely locate where they have good access to
the waterfront area and support base. Location flexibility is tied to
the bulk of items supplied offshore. A company shipping large volumes
or bulk items, such as the mud supplier, will locate adjacent to the
harbor, with access to rail, road and water transportation, while companies
responsible for small component items, such as a catering service, can
locate in the general vicinity of the harbor. Other factors, including
startup and operating costs, will have a major influence on site selection
by these firms.

Operations

General shore support companies receive materials destined for
offshore facilities, and store and/or modify the materials until they
are required offshore. Offshore rigs and platforms have limited storage
facilities. Operating characteristics relate closely to services provided,
and the total effort needed to make the contracted services and materials
available on demand offshore. In general, shore support businesses are
similar to a warehouse supporting heavy construction activity, with
large supplies of necessary materials stockpiled and most activity
associated with moving it or modifying it to meet specific offshore
needs.

Community Effects

General shore support encompasses a variety of specialized companies
serving the offshore industry. Each company will provide a few local
employment opportunities, normally in the general labor category [19].

144

Construction/ Installation

Onshore support firms use existing space and facilities. With the
possible exception of the mud supplier, installation and construction
activities for individual firms are insignificant. Collectively, how-
ever, they may have an effect on a single harbor. In a frontier area, if
a new service base is constructed, it is likely that many general support
facilities will lease space within the service base.

Employment: Employment data for 15 to 20 representative companies
involved in shore support is presented in Table 13. Employment in each
firm includes three categories: specialized skills, general labor, and
administrative staff. If all potential firms moved into a single area,
the effect on local employment and commercial space would be significant.
Therefore, it is important to understand conditions under which individual
firms prefer to locate in the adjacent onshore area rather than service
offshore operations from a distance. Table 14 lists threshold values,
as expressed by the Offshore Operations Committee, for selected support
companies in one frontier area, the Mid Atlantic lease sale. If these
companies move into an area gradually, they will have less impact on
local employment over a longer term than most other facilities associated
with OCS development. Major impact could occur if a large number of
firms establish new facilities in a small area within a limited timespan.

Induced Effects: Induced effects may be important from an employment
perspective, but should be negligible in terms of facility needs at the
site. Each company will bring at least some administrative staff from
established facilities. Individuals in these higher paying jobs as well
as other employees with special skills brought in by the firm, will
require housing and local services.

Effects at the site will be negligible because requirements are
small in terms of service demands, and firms will try to locate in
vacant commercial space. Most of these firms have limited investment
capital and prefer to conduct their operations in leased facilities.
This strategy reflects the lifespan of an oil field, the specialized
nature of most support services within the phases of OCS activities, and
the fact that purchase of the property would mean a need to sell when
the shorefront commercial land market is depressed because the offshore
field is shutting down.

Effects on Living Resources

General shore support companies have the following characteristics
of particular fish and wildlife concern: (1) many and small acreages
for industries ancillary to the major oil companies; (2) berths, channels,
piers and bulkheads; (3) storage areas; (4) service areas and operations
shops; (5) administrative buildings; and (6) parking lots.

145

Table 14. Industry Estimates of Onshore Facility Requirements
for OCS Oil and Gas Operations in the Baltimore Canyon
(Source: Reference 36)

Number of Facilities
Required for Full
Development of
Stimulus Region Company Type

minimum of 10-20 rigs 5 Mud Suppliers

working to establish Wireline Company

one facility (10-20 Gas Lift Company

rigs could attract Logging and Perforating

2 to 3 facilities) Company

Cement Company
Supply Store

minimum of 10-20 rigs up to 10 Welding Shops

working to establish Machine Shops

facility Fishing Tool Company

Rental Tool Company

minimum of 10-20 rigs 3-5 Wellhead Equipment

working to establish Supplier

facility

minimum of 10-20 rigs 6 Downhole Equipment

working to establish Companies

facility

minimum of 10-20 rigs 5 in addition Machine Shop

working to establish to existing

facility facilities

minimum of 10-20 rigs 2 in addition Trucking Firm

working to establish to existing

facility facilities

minimum of 10-20 rigs Not more than 1 Diving Service

working to establish
facil ity

146

Location: For some of the general shore support industries a
waterfront location will be necessary to have raw materials and supplies
arrive and depart by barge or ship. This will mean that piers, floats,
and dolphins will have to be constructed and berths and channels dredged.
Dredging should be performed only with protective devices, such as
sediment screens, and by techniques that keep sediments to a minimum,
such as working only on the outgoing tide. Existing facilities
should be adapted to accommodate these many small industries.
The location of these facilities at the entrances of harbors and
rivers with significant flushing rates will aid in the dispersal of
propeller-generated silts and sediments. Additionally, erosional
runoff from unpaved storage areas and parking lots will be more
quickly transported rather than settling in adjacent salt marshes,
clam flats, etc., where organisms could be smothered. Industries that
have no direct coastal connection should be situated on the upland.
Wetlands should not be filled to obtain new area because of the loss of
vital fish and wildlife habitat.

Design: Where general shore support industries have service areas
and operations shops, grease and oil traps should be installed and
properly maintained. This will reduce the amount of petroleum products
reaching runoff water. All cooling water that may have contacted
petroleum or other contaminant material should be treated before it is
allowed to re-enter natural water bodies. Compressors and other equipment,
which may exceed acceptable noise levels should be housed or. provided
with muffler devices to reduce the sound levels. Bulkheads should not be
used as substitutes for piers. Solid fill bulkheads interrupt littoral
drift and cause sand to be diverted from downshore areas which were'
previously supplied by the along-shore currents.

Construction: Heavy equipment must be scheduled to avoid operations
during sensitive periods of fish and wildlife cycles, such as
spawning/breeding, rearing, etc. Erosional sediments from runoff may
cover fish eggs causing failure to hatch, while noise and other disturb-
ances may be disruptive, especially in or near endangered species habitats,
If construction is to occur in wetlands, the heavy equipment should use
construction mats to protect the area from long term damage by tractor
treads, truck wheels, etc. Existing service roads should be utilized as
much as possible and should be strengthened to accommodate the loads of
heavy equipment.

Operation: If oil or gas is to be stored above ground on the
premises for operations, dikes around the tanks should be able to accom-
modate the full contents of the tanks. Each tank should have its own
access road and the tops of dikes should not be used as service roads or
be traversed by vehicles that could erode surfaces. All waters involved
with processes should be collected in a central system for treatment,
such as aeration, precipitation, etc., to reduce pollution loads when
the water re-enters the natural water course. Operations that create

147

dusty or dirt-laden air should be enclosed and utilize dust-bags or
other devices to prevent local problems with air quality.

Regulatory Factors

State and local permits and certifications required for shore
support facilities will be dependent on which required facilities are
already available. The development or expansion of new facilities will
require new permits dependent on their size and location. The general
description of state and local programs in Section 2.1.3 indicates the
nature of permits and certificates commonly required.

Federal Role: Federal permits for new construction affecting
wetlands or requiring maintenance or channel dredging would be issued by
the Corps of Engineeers. The procedures and comment functions of the
Fish and Wildlife Service are described in sections discussing Platform
Fabrication (2.3.4) and Service Bases (2.3.1). Other Federal permits
may be required dependent on the nature of the facility. The list of
Federal programs dealt with by programs of the FWS in Section 2.1.3
illustrates the concerns a sponsor must consider.

Development Strategy

The strategy of the shore support firm is based upon attaining a
threshold level of potential business offshore. If demand is less than
the threshold level, which varies greatly among this diverse group of
firms, a firm will ship its products or conduct its operation from an
established base. Thus, if a single COST hole is being drilled prior to
leasing, muds, pipe and all other necessary materials are shipped in
from established bases, even though quite distant.

As a frontier field passes through the exploratory phase and
commercial quantities of petroleum are located, additional support
companies find it financially advantageous to locate in the frontier
harbor area adjacent to or within a supply base. The threshold is
reached when a firm can reduce its total costs, which include transporta-
tion, processing, and administration, by locating in the frontier port
area.

In a frontier area harbor with a support base, there usually
will be only one firm contracted to perform each specialized func-
tion. Probable exceptions are trucking firms, machine shops, and
welding shops. If firms have no competition, they have much greater
locational flexibility and can attempt to minimize costs rather than
maximize potential business in selecting a site.

148

The strategy of these firms is independent of petroleum company
field leasing and development strategy. These firms follow petroleum
companies into frontier areas. Such support firms monitor all petroleum
company activity trends as their viability depends on continued contracts,
About half of the businesses cited earlier in this section, such as a
downhole equipment company, sense the specific needs of the petroleum
industry.

The remaining firms either serve the petroleum industry as one of
many customers or are already located in the frontier area to serve
other commercial enterprises. For these firms, the initiation of OCS-
related activities means new contracts and an increase in business.
These businesses will merely expand to accommodate the special needs of
the petroleum industry.

149

2.3.4 Platform Fabrication Yards

Production platforms are installed offshore to support drilling and
production operations and to provide crew housing and supply storage
(see Figure 33). The types of platforms currently in use are fixed-
pile platforms, usually made of steel, and gravity platforms, made of
steel or concrete and held to the bottom by their own weight supplemented
with ballast. Platforms are composed of a superstructure called the
"jacket", and "deck" for drilling operations which sits on top of the
jacket. They are described in Section 2.2.3 -- Production Drilling.

Fiqure 33. Platform fabrication yard - project implementation schedule.

INVESTMENT COMMITMENTS:

Site Purchase

Site Option(s) Taken

Start of
Construction

YEARS •••

PERMIT ACQUISITIONS:

Beqin Yard
Operations

Acquisition of Use and
Location Permits

Operating Permits

Preconstruction Permits
(Includes EIS)

The fabrication of these immense structures and the platform jackets
is done in specialized facilities known as platform-fabrication yards.
These yards have the highest impact on coastal environments of any
onshore facility required by offshore oil and gas development. A fabrica-
tion yard requires more land on the waterfront, more heavy industrial
materials, and a much larger labor force than any other onshore project.
Due to the extensive requirements of a fabrication yard, it will invariably
become the nucleus of numerous ancillary service and supply companies —
welding supply, marine repair, and heavy equipment sales.

150

Within the United States there are four large fabrication yards
which receive all the major platform business. Three of these are on
the Gulf Coast where the bulk of U.S. offshore activity has long been
concentrated, and one is on the Pacific Coast. Two of the Gulf Coast
yards dominate the U.S. platform fabrication business -- Brown and Root,
whose yard is near Houston, Texas, and J. Ray McDermott, whose yard is
just east of Morgan City, Louisiana. The third Gulf Coast yard, operated
by Avondale Ship Yards, is also near Morgan City. The fourth major U.S.
yard serving the west coast market is owned by Kaiser Steel Corporation
at Oakland, California. Each of the Gulf Coast yards occupies about
1,000 acres of land, and each has the capacity for building two or more
platforms simultaneously.

The Gulf Coast yards have fabricated platforms for both the U.S.
and international oil and gas drilling. Approximately 20 percent of
Brown and Root's production of platforms from their two Gulf Coast yards
are for foreign countries [37]. The few platforms installed in Alaska
have been built in the "lower 48." Kaiser has built at least six of the
14 platforms located in the Cook Inlet area of Alaska [38].

The Kaiser yard recently completed the world's largest platform
superstructure (jacket), which has been installed in Exxon's Hondo field
in the Santa Barbara channel— it is 865 feet high and installed in a
water depth of 850 feet which is nearly twice the depth of any other
offshore jacket. The total height of the Hondo structure is 945 feet.

Unless the demand for platforms in new U.S. frontier areas is
heavy, based on large finds, their fabrication can easily be handled in
the four existing major yards. Two large yards have been proposed by
Brown and Root: a 980 acre site at Cape Charles (Northampton County),
Virginia [39], and a 400 acre site at Astoria, Oregon (to be operated by
a Brown and Root subsidiary. Pacific Fabricators, Inc.). These facilities
were proposed recognizing the lengthy process preceeding construction and
in anticipation of possible large finds in offshore frontier areas.
Each proposal includes a dry dock so that large, self-floating platforms
can be fabricated. These yards could both begin operations in 1978 and
ultimately have an employment of 1,200 people or more. Both yards were
initiated (i.e., land optioned) before leasing and exploratory drilling
occurred.

Description

Fabrication yards occupy from 200 to 1,000 acres of cleared level
land adjacent to a navigable waterway of adequate depth (usually 15 to
30 feet). Major facilities may include a dry dock (graving dock),
jacket-fabricating area, pile-fabrication rack, deck- and modular-
assembly building, pipe-rolling mill, plate and pipe shop, painting and
sandblasting shops, electrical shops, and warehouses. Approximately 60

151

percent of the yard area is used for welding large tubular steel jackets;
fabrication work areas are adjacent to bulkheaded shorelines, except
where a large dry dock (graving dock) is installed for final assembly of
the largest self-floating jackets. The remaining 40 percent of the yard
area is used for: storage of steel plate and structural sections which
are cut, rolled, bent, and welded into prefabricated partial units;
parking lots and administrative buildings; the welding and machine
shops; and the large hangar- type deck-fabrication buildings. Figure 34
shows the site plan for the proposed platform-fabrication yard at Cape
Charles in Northampton County, Virginia.

Site Requirements

The site requirements for a fabrication yard include the availability
of a skilled labor pool, access to established transportation networks,
access to high voltage power, a large flat site with adjacent deepwater
channels, and a sheltered harbor.

The required length of the wharf depends on the number and size of
the platforms (steel) being constructed at any one time. Since the
jacket is constructed perpendicular to the wharf, the length of the
wharf is determined by the bass height of the platform and the number of
platforms lined up at the waterfront [26].

The required water depth at dockside and in the channel varies with
the type of platform being constructed. For fixed-pile platforms, a
depth from 15 to 30 feet is normally required. For gravity platforms,
particularly cement gravity platforms, much deeper water is required.
Once the concrete base is completed in dry dock, the base is floated and
moved away from dockside to depths of from 240 to 300 feet. This deepwater
site must be sheltered and within a few hundred yards of the fabrication
yard.

The smallest facility producing platforms is 50 acres, but larger
yards require between 200 to 1,000 acres, with 300 acres the average.
Some yards are considerably larger. Brown and Root's proposed Virginia
site is 980 acres, of their total land holding in the area of 2,000
acres. The availability of the land can have important effects on the
size of the yard, initially as well as later on when expansion is con-
sidered. If the land at the chosen site is abundant and inexpensive,
the sponsor will likely option or purchase a larger parcel than if the
availability or price was restrictive [26].

For steel platforms the channel width should be up to five times
the beam of the largest barge to be towed from the fabrication yard.
The average beam of such barges is 60 feet; therefore, the channel width
is usually 300 feet. Because of the difficulties involved in towing
gravity platforms (such as clearance requirements, weight and height).

152

Figure 34. Site plan for Brown and Root platform fabrication
yard at Cape Charles in Northampton County, Virginia
(Source: Reference 39).

Rt. 642

SITE PLAN

ADMINISTRATIVE, ENGI-
NEERING, AND TRAIN-
ING SCHOOL

VESSEL FABRICATION
YARD AND STORAGE

MARINE JACKET

FABRICATION AREA
AND STORAGE

MODULE FABRICATION
AREA AND STORAGE

FILL AREA

NATURAL SUITER ZOME

153

concrete fabricators prefer not to navigate a channel to reach their
deepwater construction site.

The average required clearances for both the vertical and horizontal
dimensions in the access route from the fabrication yard to the open sea
are from 210 to 350 feet, depending, of course, on the size of the
platform and the required margin of safety [40]. Where bridges can be
opened, horizontal clearances should also be determined. Vertical
clearance requirements for gravity platforms are much greater than for
steel platforms. Since pillar and superstructure heights can exceed 400
feet, bridges of any kind are probably unacceptable [26].

The transportation of raw materials, personnel, fuels, stores,
equipment, and machinery and parts for a fabrication yard is likely to
require all four principal forms of transportation--air, road, rail, and
sea. The magnitude of traffic will vary with the type and number of
platforms under construction. The volume of raw materials required for
a cement gravity platform, for example, can be as much as ten times that
required for a steel platform. If a spur line is available or constructed,
a two-platform cement yard could require three train deliveries per day
for raw materials (aggregate, cement, steel). Also required would be
two rail tank cars per week for fuel and lubrication oils and one rail
car per week for machinery and spare parts [26].

If a source of raw materials is available near a waterfront site,
cement-platform yards would be likely to receive the materials by barge--
an estimated two to three 3,000 ton barges would be required every two
weeks. Generally, because shipping is the least expensive transportation
alternative, fabricators will ship major materials to the yard if at all
possible.

In contrast to the broad range of potential steel -jacket-platform
sites, the choice of a concrete-gravity-platform fabrication site is
largely dependent upon proximity to the drilling site. Concrete-
gravity-platforms are too heavy and massive to be towed long distances;
if they are to be used in Alaska, they will have to be constructed in
Alaska.

Since platform-fabrication yards employ hundreds of skilled iron
workers and welders, a sponsor will attempt to locate in the vicinity of
a labor pool which has an abundance of these skills. Areas with existing
ship repair and construction yards have available welders and other
skilled craftsmen in the work forces. However, many of the skilled
workmen and management staff may be imported from existing Gulf Coast
fabrication yards, to provide a nucleus of personnel who know and under-
stand the fabrication business. In order to accommodate the total
workforce required (up to 1,200) a sponsor will also attempt to locate
near a community capable and desirous of accommodating industrial-based
growth.

154

Construction/Installation

The first step is preparation of the fabrication site itself,
including dry dock, road and rail spurs, yard, dockage, and storage
areas. Site preparation can take as much as three months to a year,
depending on the size of the facility [26].

When ready for fabrication, the site should be 5 to 15 feet above
mean high water in adjacent navigation channels. The waterfront site
required for a fabrication yard may involve a high probability for
wetland and shoreline alteration in the construction of the facility.
Most of the site will be cleared of vegetation and graded by large
earthworking machinery. Parts may require being filled and stabilized
with sand and gravel from adjacent waters or lands. Existing channels
may have to be deepened or widened to provide a turning basin and access
to deepwater channels for marine traffic— barges, tugs and platforms.

Operations

Steel platforms are made up of two sections--the deck and the
jacket. The jacket serves as a base to support the deck section. The
jacket is composed of huge steel tubular members welded together to form
a stable base. When completed, it is rolled on dollies or rails onto a
launch barge and towed to the installation site.

The deck section includes the drilling and production facilities,
living quarters, helipad, and whatever else may be required, depending
on the complexity of the platform. The deck section and its attached
units are built in large construction sheds, sometimes in distant areas.
Wherever completed, the deck section is barged separately out to the
installation site.

Gravity Platforms: The assembly of gravity platforms differs
markedly from that of fixed platforms. Since there is little difference
between steel or concrete gravity platforms, apart from materials involved,
the focus here is on concrete platforms.

The base of the platform, usually composed of many cylindrical
prestressed concrete cells, is constructed vertically in a dry dock
(graving dock) immediately adjacent to deep water (150 to 300 feet).
When completed, in about nine months, the gravity platform is floated
out of dry dock; its ballast cells are filled, and the base section is
partially submerged to permit further vertical construction. If the
platform is to be used in shallow water, all that is necessary at this
point is to affix a deck section to the base and to add the appropriate
drilling, operations, storage, and living quarter modules; then the
platform is ready for deployment. However, since concrete platforms are
more often used in wery deep water, huge concrete pillars, or towers,
are constructed atop the partially submerged base section. The con-

155

struction of these pillars can take from 9 to 15 months. At this point
the fabricator is likely to tow the concrete structure to even deeper
water (100 fathoms) to give it a submergence test prior to installation
[?6].

Community Effects

A fabrication yard has the following characteristics of particular
interest to the community: (1) potential for high employment and community
growth; (2) potential for high investment and a broader tax base; (3)
large parcel of land involved; (4) high service requirements and (5)
extensive commerce in raw materials.

Employment: The construction of a platform-fabrication yard will
require approximately 500 laborers; up to 1,200 people will be hired to
construct platforms. Employment will vary greatly depending upon the
number of platforms and jackets under construction at any time. As many
as 90 percent of these workers will be local residents. The presence of
a major new industry will attract unemployed individuals who will also
compete for jobs. Most jobs are for fabricators and welders who can be
trained locally if necessary skills are not available. Activities in
adjacent and nearby communities to support these workers and their
dependents--home construction, increased commercial activity, and demands
on public services--are a potential source of disturbance to fish and
wildlife resources and habitats.

Induced Effects: Analysis of a fabrication yard proposal illustrates
the potential scale of effects. Requirements of the proposed Brown and
Root fabricating yard in Northampton County (Chesapeake Bay eastern
shore) in the State of Virginia indicated the following estimated effects:
1,670 new residents; 125,000 square feet of new commercial space; increased
demand for domestic water supplies of 850,000 gallons a day; increased
sewage load of 600,000 gallons a day; increased student enrollment of
1,100; and increased solid waste disposal of 15,000 tons per day [39].
In more rural environments, where these facilities are likely to locate
because of the large parcel of shorefront land required, disruptions of
this magnitude on services are substantial.

Effects on Living Resources

A platform-fabrication yard has the following characteristics of
particular concern to fish and wildlife: (1) waterfront location; (2)
large use of coastal land area; (3) possibility of wetlands filling; (4)
dredging of shipping channels and spoil disposal; and (5) possibly dry
dock (graving dock).

Location: A platform-fabrication yard must have a waterfront
location. While this location need is common to other industries, the

156

important factor in this case in the amount of fish and wildlife habitat
that may be displaced in establishing a yard. Although there are few
yards larger than 1,000 acres, the siting of a facility may utilize a
large amount of coastal land and therefore have significant consequences
for local habitats. Large acreasges of coastal upland for a facility of
this type are usually unavailable; the unfortunate alternative is the
extensive filling of wetlands.

Design: To service a platform-fabrication yard, it is necessary to
design navigation channels and a turning basin for launching platforms
when completed. The dredging of new channels or the deepening of existing
ones will create turbidity and sedimentation in the water and may lead
to the smothering of organisms, such as clams and corals. It may also
cause reduced photosynthesis because of the decreased penetration of
sunlight. If spoil disposal sites are selected too close to sensitive
species habitats, there may be detrimental effects on indigenous species
from the dumping of materials. If concrete platforms are to be con-
structed, a large dry dock (graving dock) will need to be excavated. The
Corp of Engineer's Dredge Material Research Program has developed guide-
lines and techniques to reduce the effects of dredging and disposal
operations which include turbidity-reduction dredge types, operational
techniques and scheduling tables [41].

Construction: With the need for platform yards to be relatively
flat, the major construction activity is alteration of the topography
into a flat area. Large open areas are needed for storage of raw materials
for the platform- fabrication sections, so vast areas are cleared of
vegetation. This causes a drastic change in the microclimate of the area
making it uninhabitable for the wildlife species which previously occupied
the sector. With the vegetation removed, erosion may occur if appropriate
measures are not taken to control it. Without proper control there may
be excessive sedimentation into streams and rivers producing degraded
fish habitats.

Operation: The applicant's major environmental problems in operation
will be meeting EPA pollutant-discharge standards on waste disposal and
runoff water; other environmental problems will involve maintenance and
the disposal of dredge spoil.

Regulatory Factors

A platform-fabrication yard requires an onshore site of substantial
size. Access to open water, demands for electricity, raw materials,
transporation, and water for industrial use also pose potential regulatory
problems. The onshore site is likely to be subject to Federal, state,
and local regulations setting conditions for different aspects of
construction. In general, a site in an existing industrial area will
receive less regulatory scrutiny from local government than one located
in residential or undeveloped natural areas.

157

state Permits: Most states have regulations requiring a permit for
alteration or filling of wetland areas. Other state-level concerns
include utility planning for high voltage electrical service, and air-
and water-quality regulations governing industrial processes. In some
states large scale development may also trigger a state permit or review
process. The 1976 Amendments to the Coastal Zone Management Act require
special planning elements for states that wish to qualify under its
provisions. These plan elements, once approved by the Office of Coastal
Zone Management, may influence Federal decisions as Federal actions must
be "consistent" with the approved state program.

Local Permits: Unless a fabrication yard is located in an area
where industrial development is already permitted, zoning approval for
industrial uses will be required from a local government unit. The
requirements of zoning regulations vary from one community to another,
and zoning permission may be denied as a matter of local policy at any
time before a sponsor begins construction. Other local permits referred
to in Section 2.1.3 are less likely to be encountered or to pose
substantial obstacles to development.

Federal Role: The waterfront location required for platform
fabrication ensures Federal involvement in the development-approval
process for dredge and fill permits before wetlands development or
channel maintenance. The Corps of Engineers manages the permit program
under the authority of Section 10 of the Rivers and Harbors Act and
Section 404 of the Federal Water Pollution Control Act Amendments of
1972 in partnership with the Environmental Protection Agency. Court
decisions have extended the limits of Corps implementation efforts from
the "navigable waters" governed by Section 10 to the "waters of the
United States" governed by Section 404. With exceptions related to the
size of the lake or stream and agricultural use, permits are required
for activities in all wetlands and water areas.

Implementation of dredge and fill regulations takes place at the
District Engineer level along with the participation of the Regional
Office of the Fish and Wildlife Service and the Environmental Protection
Agency. The Corps must request the advice of the Service on every
application. If the Regional Director of the Fish and Wildlife Service
files a timely objection to permit issuance, the matter is first referred
to the Corps' Division level for review, and unless the objection is
withdrawn, then to Washington to be settled between the offices of the
Secretary of the Army and the Secretary of the Interior.

The Fish and Wildlife Service advises and comments on wildlife and
habitat and possible mitigation actions which will reduce the impact of
a proposed project on them. Other specific authorities add to FWS
responsibilities in Federal permit review. Regulations governing the
Corps of Engineers procedures are found in 33 Code of Federal Regulations
Section 209. The Fish and Wildlife Service operates under a separate
set of procedures described in Volume 40 of the Federal Register, page
55810, published December, 1975.

158

The Fish and Wildlife Service is primarily responsible for the
implementation of the Endangered Species Act. This act prohibits
destruction of the habitat of certain listed plant and animal species by
Federal agencies or under Federal permits.

Development Strategy

Platform-fabrication yards are built by companies that specialize
in the construction and erection of offshore facilities under contract
to the oil companies (which are the offshore operators). Yard sponsors
stay in close contact with the offshore operators to ascertain future
regional demand for platforms. By comparing the anticipated demand for
platforms with the capability and location of existing yards, the
fabricators can evaluate the needs for additional fabrication yards to
serve new demands in developing fields. As previously stated, unless
there are major finds, there will be no additional major platform yards.

Among the most important considerations are: (1) an estimate of the
demand for platforms and the timing of that demand; (2) the location of
the find, therefore, the type of platform likely to be in demand; (3) an
estimate of the portion of the market that can be captured; (4) labor
availability and restrictions; (5) proximity to the find and, (6) water
depth and climatic conditions in the frontier area.

Basically, the fabricator desires to find a reasonably sized and
situated tract of level land within economically practicable distances
from the offshore installation sites, that also has close access to
water of sufficient depth to allow movement of the platforms from the
yard to open water and on to the installation site.

In addition to the unpredictability of demand by new fields, the
excessive overbuilding during the past few years of both tankers and
mobile drilling rigs caused a sharp downturn in the U.S. and worldwide
shipyard activity. This downturn, expected to continue through 1980,
has freed shipbuilding facilities to convert and to enter the platform-
fabrication business, thus potentially reducing the need for new yards.

The strategies of the offshore operators and platform fabrication
sponsors are largely but not totally compatible. The sponsor wants to
limit investment in the yard until an initial contract order is signed.
Therefore, the sponsor would prepare all engineering studies and would
acquire all permits for yard construction but would not initiate con-
struction activities. On the other hand the offshore operator would
benefit from the maximum development of the yard prior to contract
orders so that production can be initiated at the earliest possible time
after confirmation that recoverable quantities of oil exist under the
OCS site.

159

Offshore operators and platform fabricators have a mutual advantage
in having a yard ready for production soon after a commercial -si zed
field is found offshore; the sooner drilling and production can begin,
the sooner the operator can begin to earn a rate of return on the vast
sums already invested in lease payments and exploratory drilling. By
having a yard ready for operation when orders for platforms are received,
the fabrication firm can assure early delivery and thus can compete
favorably with other firms for the business.

The platform sponsor generally, though not always, makes the decision
to establish a strategically located yard after a significant find has
been made and its development schedule has been set.

The sponsor may speculate on future sites. Even before lease sales
occurred. Brown and Root purchased land in Virginia and optioned land in
Oregon without making a commitment on a yard.

While the oil company is in the process of delineating the field
within which the find has been made, the platform sponsor will hold
meetings with oil company representatives to estimate the number of
platforms that might be needed to draw up a possible schedule for delivery,
and to draw up preliminary design specifications for platforms as the
nature of the field is determined. Other information likely to affect
the choice of platform type might include location of the find, the
seabed conditions, the depth of water, and other requirements. The
choice of platform type will determine the amount of lead time required
for obtaining steel and manpower.

To summarize: a platform fabrication yard is usually sited and
planned well in advance of offshore production drilling, and the platform-
fabrication companies may obtain an option to buy or lease a suitable
tract of land well in advance of an offshore lease sale; the fabricator
may not act on this option until he is assured of platform orders. An
option allows the fabricator to proceed with environmental impact
statements, zoning applications, site layout, design of facilities, and
applications for building permits; having accomplished these preliminaries,
the fabricator is ready to rapidly construct the yard once a platform
order is received. Once an order is received economic forces and the
rush to develop the newly discovered field causes a burst of activity
with momentum that may not easily accommodate environmental concerns.

At the time of taking land options environmental considerations can
be easily incorporated into the plan for the fabrication yard. The
ability to insert environmental recommendations continues to the time a
platform order is received.

Investments: Securing an option on land and initiating environmental
studies and designs of yard facilities does not assure that the yard
will become a reality. Until the market for platforms has firmed up, a
new platform yard may not be constructed since at least three large

160

platforms must be built before a new yard will return a profit. Advance
money spent on the above simply gives the sponsor an advantage over his
competitors when a platform is finally ordered. Though the sponsor may
invest up to $1 million in preliminary work, this is only a fraction of
the price of a completed steel-fabrication yard, which may cost from $20
•to $40 million, or of a large deepwater platform fabrication yard, which
cah exceed $100 million. Long transport distances weigh in favor of a
new yard, but the high capital costs of a new yard tend to favor
fabrication at existing yards.

161

2.3.5 Pipe-coating Yards

The pipe-coating yard is one of the more significant OCS related
onshore developments that will occur during the recovery of oil and gas.
When an oil or gas field having commercial potential is delineated, a
decision is made concerning the mode of oil or gas transit to shore for
processing. The preferred mode is very often pipelines because: (1)
fewer transfer operations occur compared to tankers; (2) pipelines
operate efficiently in all types of weather; (3) pipelines have a better
safety record than tankers; and (4) a direct, continuous stream of oil
or gas passes to the onshore refinery or gas processing plant.

The laying of a pipeline is complex and requires special techniques
for successful operation; coating is one of these special techniques.
The pipe-coating yard applies a cement coating to the pipe for two
purposes: (1) to protect the steel pipe from the corrosive elements of
sea water, and (2) to add sufficient weight to overcome the buoyancy of
the lighter oil and/or gas (See Figure 35). The technique and the
intricacies of laying pipe underwater have led that operation to be one

Figure 35. Pipe-coating yard, project implementation schedule.

INVESTMENT COMMITMENTS:

Site Purchase

YEARS'"-

PEPMIT ACQUISITIONS:

Acquisition of Use and
Location Permits

Start of
Construction

Q Begin Yard
Operations

Operating Permits

Preconstruction Permits
(Includes EIS)

162

of the most costly in the oil and gas industry. The costs for underwater
pipe-laying can approximate $1,000,000 per mile and possibly more in
rough terrains. Therefore, it is imperative to give as much protection
to the pipe as possible to prevent costly failures of the pipeline
(e.g., leaks, bends, ruptures) due to seismic activities, improper
burial, inadequate weld, or excessive currents and tides.

Description

A pipe-coating yard occupies approximately 75 to 200 acres, the
bulk of which is used for pipe storage. A relatively flat piece of land
that has good rail and water access is necessary for efficient operation.
Forty-foot lengths of pipe are generally brought to tha yard by rail (or
by truck or barge); after being coated the weighted pipes are shipped by
sea to a waiting pipe-laying barge. The main components of a pipe-
coating yard are:

• Pipe-cleaning buildings

• Pipe-coating buildings

• Outdoor storage space

• Supplies storage buildings

• Rail terminal

• Marine terminal and bulkhead
t Administrative offices

• Maintenance and repair buildings

Site Requirements

The location of a pipe-coating yard has traditionally been in a
coastal area to utilize the marine connection to offshore operations. A
marine shipping terminal is a necessity for loading and unloading materials,
Uncoated pipe may arrive by barge, but when the coating has been applied,
the pipe must be shipped by boat to the offshore lay-barge. Raw materials,
e.g. pipe and cement, will typically arrive by land routes. Therefore
roadway and rail access are other criteria that must be satisfied in
site selection in addition to navigation channels.

Construction/Installation

Typically a pipe-coating yard must be situated on solid soil of
high load-bearing capacity because of the many activities involving
heavy equipment. With location of the yard in a coastal region, there
is a good probability that wetlands may be involved at some point in
construction. The land must be cleared of vegetation, and "soft spots"
must be excavated and filled with either sand or gravel to maintain an
acceptable working surface. Heavy equipment would be employed to rework

163

the land area for storage, while other parts would be utilized for the
construction of the pipe-coating plant and other buildings. Pipe-coating
may be done outside, depending on weather conditions and steps involved.

The construction of the marine terminal for pipe receiving and
shipping would involve the dredging of berths, a turning basin, and a
navigation channel (15 to 30 feet deep). The projects could be done
with a variety of machinery from dragline to hydraulic dredges. If the
dredged material is sand, gravel, or oyster shell, it could be utilized
for filling or surfacing the land areas, but dredge material of loose,
unconsolidated mud and clay would need a disposal site. A bulkhead
several hundred feet long would have to be constructed to accommodate
ships and barges loading and unloading pipe and materials.

Operations

The pipe-coating process has two major components: (1) the
application of an anti-corrosion (mastic) coating and; (2) the
application of a weight (concrete) coating.

Pipe first enters a cleaning building where it is scraped, brushed,
and sandblasted to remove rust and to yield a good, clean surface for
the anti-corrosive coating. The anti-corrosive coat is applied as a
hot, asphaltic mixture after which the pipe is cooled by water to reduce
the temperature and yield to a smooth mastic. Hydrated lime is added
to the freshly coated pipe to assist cooling and to prevent sticking
when pipes are stored. Electronic and other inspections determine if
the anti-corrosive coating is uniform and ready for the next step. Care
must be taken not to damage the newly applied coat.

Concrete is applied as an outer layer by being sprayed at high
speeds and by adhering to the rotating pipe giving a thick coat.
Galvanized wire wrapped around the pipe provides adhesiveness. Weighing
determines if the pipe will meet the proper specifications (140 to 190
lbs. per cubic foot) for the intended use. When finished, the pipe is
placed unstacked on sand rows to allow adequate curing, after which the
coated pipe is ready to be loaded onto a supply boat. The boat carries
the pipe from the marine terminal to the offshore lay-barge where the
pipe-laying operations are conducted.

Community Effects

A pipe-coating yard requires about 100 acres (primarily for storage),
a waterfront location or access to a marine terminal, a level site with
compacted soils, and access to transporation systems. It would probably
be located outside an urban area because of land costs, but it needs
access to a wharf or pier.

164

Employment: A pipe-coating facility processing 200 miles of 30-
inch pipe (26,400 joints) in eight months might employ up to 200 people.
This business has "boom or bust" characteristics so that employment will
come in spurts and will vary in size in response to specific orders
perhaps dropping to 30 to 40 people in slow periods. Only a small
number of supervisory personnel will move into the area; the remaining
employees will be local [26].

Induced Effects: One study has described a pipe-coating yard as
being similar in area and impact to asphalt-paving and construction
supply yards of comparable size [21]. Required services at the facility,
including water, sewage, solid waste disposal, and protection, will add
little in cost to the community. In addition, as only a few employees
will be new to the region, residential-related increases in service
demands will also be minimal. Unemployment benefits between contracts
may be a much more significant expense at the state level.

The pipe-coating operation results in airborne particulate matter.
The stored pipe is unsightly, and an empty barren yard may or may not be
an improvement. These factors could adversely affect adjacent coastal
property values. This adverse effect might more than offset benefits to
the local economy.

Effects on Living Resources

A pipe-coating yard has the following characteristics of particular
concern to fish and wildlife: (1) water and rail access; (2) large
storage area; and (3) water runoff.

Location: Although a pipe-coating yard could be located at an
inland site, it is generally located near a waterway to make use of that
transportation mode in handling bulky and heavy pipe lengths. The
location also provides immediate access to offshore drilling activities
which could only be reached with more difficulty from an inland site.
Requirements for a coastal location and a large acreage for storage make
the filling of wetlands a distinct possibility.

Design: To service a pipe-coating yard it is necessary to design
navigation channels and possibly a turning basin to accommodate ships
and barges. The dredging of new channels or the deepening of existing
ones will create turbidity and sedimentation in the water and may lead
to the smothering of organisms, such as clams and corals, and to reduced
photosynthesis because of the decreased penetration of sunlight. If
spoil disposal sites are selected too close to sensitive species'
habitats, there may be detrimental effects on indigenous species from
the dumping of materials.

With the need for a large tract of relatively flat land for pipe
storage and curing, storage areas should be designed to occupy upland

165

sectors to avoid the filling of wetlands and the loss of valuable fish
and wildlife habitat used for breeding/spawning, rearing of young, and
food production.

Construction: With the necessity for pipe-coating yards to be
flat, the major construction activity is the alteration of the topography
into level land. This requirement will cause large acreages to be
cleared of vegetation and will cause a drastic change in the microclimate
of the area. Species which previously occupied the sector will now find
the area uninhabitable. Also, with the vegetation removed, erosion may
occur if appropriate control measures are not taken. Without proper
control there may be excessive sedimentation into streams and rivers
producing degraded fish habitats.

Operation: The operations of cleaning and coating the pipe with
petroleum-based "mastic", synthetic, or cement will involve water
cooling of the newly applied material. The water from these processes
should be collected, transferred to cooling ponds, and treated by aeration
and methods to reduce contaminants prior to release into natural waterways.

Regulatory Factors

A pipe-coating yard faces many of the same regulatory hurdles that
are posed for platform-fabrication sites. State and local regulatory
programs may be as important as the Federal permits that are required
for dredge and fill and channel maintenance.

State and Local Role: State and local permits and certifications
required for the development and operation of a coating yard will depend
on the laws and regulations of the particular state, town or county in
which the yard will be located. A new yard is likely to require zoning
permission because of its size and the required water access facilities.
State wetlands or dredge and fill permits are also likely to be required.

Federal Role: The Corps of Engineers issues permits for dredge and
fill or alteration of the water areas of the United States. These
permits are issued under Section 10 of the Rivers and Harbors Act of
1899 and Section 404 of the Federal Water Pollution Control Act Amendments
of 1972.

Other important considerations in particular situations include the
Endangered Species Act and Federal highway decisions that require Fish
and Wildlife Service comment.

Development Strategy

The decision to construct a pipe-coating yard is an economic one
but beyond that, time, weather, and distance are important factors. A

166

yard is a highly specialized facility and susceptible to the boom-bust
syndrome that may accompany oil and gas development. Therefore a pipe-
coating yard is usually situated in a region where underwater oil and
gas pipelines are to be constructed in abundance. If the yard is located
too far from the intended use area, it probably will not be economical
to ship coated pipe long distances, particularly because of the increased
weight of the coated pipe. The ideal situation is to take the coated
pipe directly from the yard to the lay-barge where the pipe-laying
operations are being conducted.

While logistically and economically convenient, the shorefront
location of a pipe-coating yard is not a necessity. Not all of the
pipe-coating operations need to be conducted on the shoreline. A marine
terminal with a roadway connection to the main facility will allow the
coated pipe to be shipped to the lay-barge. For a future yard the extra
costs of transportation might be offset by the savings on the purchase
of less expensive inland real estate. A one-hundred acre site can store
approximately 300 miles of pipe and can represent an $8 to $10 million
investment [26]. Because of the demand for large quantities of fresh
water, both for the preparation of cement and for the cooling of newly
treated pipe, local supplies must be adequate, and there must be
assurances of a continuous supply.

167

2.3.6 Oil Storage Terminals

Onshore oil storage terminals are needed to receive, measure
(meter), segregate, store, and distribute various grades of crude oil and
refined products (see Figure 36). An oil storage terminal and a tank
farm are synonymous. Terminals built to store the oil being produced
from offshore fields have a constant inflow of oil from crude-collecting
pipelines and an intermittent, very rapid outflow to tankers and refineries.
Terminals built to store oil for one or more refineries have an intermit-
tent, very rapid inflow of oil as tankers unload and a constant inflow from
o-'l field pipelines; they have a smaller, constant outflow of oil to
refineries. Oil storage terminals, then, are essentially surge tanks
which help to eliminate interruptions and instabilities in an oil transfer
and processing system. Oil storage terminals insure a continuous supply
of crude oil from production areas to refineries.

Figure 36. Oil storaoe, project implementation schedule.

INVESTMENT COMMITMENTS:

Site Purchase
Site Option(s) Taken

Start of
Construction

YEARS"*'

PERMIT ACQUISITIONS:

Begin Use
O of Storage
Facilities

Acquisition of Use and
Location Permits

Operating Permits

Preconstruction Permits
(Includes EIS)

168

The primary purpose of oil storage terminals is to facilitate the
rapid loading and unloading of tankers. There are two primary reasons
that rapid oil transfer is desirable: (1) economic, and (2) logistic.
First, tanker "downtime" during unloading is costly. The faster the
tanker can unload and return for more oil, the greater will be its
profit. Secondly, since stormy weather can often interrupt oil transfer
operations, the faster that oil can be transferred, the shorter the good
weather period required, and the fewer the chances for weather caused
interruptions.

Description

An oil storage terminal consists of numerous large cylindrical
steel storage tanks, oil -pumping and coolant-water equipment, inter-
connecting pipelines, an administration and control building, and large
diameter crude-oil pipelines. A typical storage terminal handles a
volume of one million barrels of oil per day (Figure 37).

Surrounding an oil storage terminal, as well as each of its individual
tanks, is an earth or concrete dike. The dike excludes floodwaters and,
in the event of a tank rupture, retains the oil within its boundaries.
These dikes also facilitate the collection and the treatment of storm
water runoff to remove oil contamination.

Oil storage terminals also include several water collection and
treatment systems. A small sewage treatment system is included to
handle domestic sewage. A storm water collection system collects and
discharges unpolluted storm water runoff. A third system is used to
collect runoff plus water from processing that has come in contact with
or is polluted with oil. Oil separation facilities and aeration ponds
clean up these waters prior to discharge. These oil treatment facilities
can be of considerable size if oil ballast water is discharged at the
terminal, as it will be at an oil transfer terminal geared to oil export
via tankers.

Oil storage terminals also have fire-fighting facilities. A pond
providing water to extinguish fires will be constructed onsite if the
terminal is not adjacent to water. A fire station with several pump
trucks is required.

The steel tanks at an onshore oil storage terminal can be of two
types--fixed roof or floating roof. Each time a fixed roof tank is
filled, the hydrocarbon vapor in the void of the tank is displaced and,
therefore, discharged to the atmosphere. A floating roof tank eliminates
this problem and greatly reduces emissions because it moves up and down
on the oil's surface accommodating only the volume of oil within the
tank.

169

Figure 37. Schematic layout for a typical surge tank farm -
example from 1.0 MM BPD refinery shown (Source: Reference 40).

CRUDE OIL
STORAGE TANKS

THIS SPACING TO BE

AT LEAST ONE TANK DIAMETER

, 15 TO W M^I,ES

CRUDE AND BUNKER
PIPELINES TO
OFFSHORE FACILITIES

==^ *===•=»»

N01 10 SCAU

An oil storage terminal will usually have an electric power sub-
station on site. The substation is necesary to step-down high voltage
power so it can be used to power the terminal's many pumps. From 5 to
15 megawatts of power may be needed in a large storage or transfer
terminal .

The volume of storage necessary for a storage terminal serving
refineries is dependent on the volume of flow between the terminal and
the refineries, the size of the tankers served and the frequency of
their arrival, and the duration of bad weather shutdowns.

Shown in Table 15 are the storage requirements related to where the
petroleum is pumped from the vessel and the daily volume of oil handled

170

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171

by the terminal. Deepwater terminals are usually in more exposed locations
and therefore need larger storage capabilities to mitigate the effect of
shutdowns during bad weather.

An oil-storage terminal near the oil field usually necessitates
another oil storage terminal near refineries because a down-surge due to
unloading of field storage tanks onto tankers will obviously cause an
upsurge of oil when the tankers unload at refineries. Thus if oil is to
be transferred by tanker, two oil storage terminals are necessary.

Site Requirements

The site of oil storage terminals is largely determined by where
offshore oil fields, tanker transfer terminals, and refineries are
located.

Oil storage terminals which are built to store offshore oil for
export are usually sited as close as possible to the shore. This aids
in minimizing pipe-laying costs from the offshore field to the storage
terminal and from the storage terminal to a transfer terminal. They
will also be near a deep (up to 40 feet), sheltered harbor to insure
safe tanker operations. Areas with considerable vessel activity will
probably be avoided due to the danger of collisions.

Oil storage terminals that serve refineries will be sited between the
tanker offloading terminal and the refineries served, in as central a
location as possible. Terminals serving refineries do not need to be in
immediate proximity to the coast, but can be 10 to 15 miles inland.
Locations near the tanker transfer terminal are preferred, however,
since different grades of crude are received and shorter receiving pipelines
facilitate easier segregation of crudes into different tanks.

Shown below in Table 16 are the approximate flat land requirements

Table 16. Approximate Land Requirements for Surge Tank Farms
(Source: Reference 26)

Surge Tank Capacity (barrels) Land (acres)

1,000,000 17

2,000,000 37

3,000,000 50

3,500,000 58

6,000,000 95

172

for an oil storage terminal. If sloping land is used, more land will be
necessary to provide equal amounts of storage as flat land areas. In
sloping areas, the tanks can be located on tiers. Shown below are the
diameters for various sized tanks with a height of 64 feet:

Tank Capacity Diameter

(barrels) (feet)

250,000 180

500,000 240

750,000 290

It can be seen that as volumes increase, a larger level area will be
needed. To provide flat areas or tiers on sloping ground will necessitate
considerable grading and even excavation. More earthwork will be needed
to provide protective dikes around each tank. Thus, flat land is highly
preferred because of the lower costs and fewer difficulties of constructing
an oil storage terminal.

Oil storage terminals will be located above the 100-year flood zone
if possible. In areas subject to tsunamis (tidal waves associated with
earthquake and/or volcanic activity), they will be located at least a
hundred feet above high water. High locations are also preferred because
they permit gravity discharge of tanks, thereby reducing the power
requirements of the terminal.

Oil storage tanks require foundations that are not subject to
settling and that have a bearing capacity in excess of 7,000 pounds per
square foot. If bearing capacity requirements cannot be met, pile
foundations are necessary.

Construction/Installation

The construction of an oil storage terminal will require land
clearing, grading and earth work operations, retention dikes, access
roads, and parking areas. If the site is only slightly above water,
considerable dredging and filling may also occur to raise the elevation
of the site. These various operations will all require the use of heavy
construction machinery such as bulldozers, drag lines, and graders.

Oil storage terminals are usually constructed by a consortium of
construction companies, each of which specializes in a certain type of
work. One company may do most of the earth work (grading and foundations),
whereas another will fabricate the tanks and install the terminal's
piping and electrical networks. These subcontracting companies will
work for a principal contractor who often designs the facilities and
then inspects and supervises the construction. The principal contractor

173

is responsible to the owner of the oil storage terminal who is usually
one of a group of oil companies. Construction of a large oil storage
terminal will require approximately two years.

Operation

Operation of an oil storage facility is highly automated, so that
only a small work force is required. There is a constant inflow of oil
from pipelines and outflow of oil to refineries, with intermittent but
very rapid flow between storage facilities and tankers.

After oil is piped ashore, it is temporarily stored in tank farms
prior to shipment for processing. By constrast, natural gas is piped
directly from the offshore site to processing plants. The output from
offshore production may involve both oil and gas which can be piped to
shore in the same line. In that event, the oil and gas will be separated.
The oil will go to a tank farm and the gas to the processing plant.

Community Effects

Oil storage terminals, or tank farms, are generally located in
coastal areas to accommodate supplies from offshore pipelines, shore
transfer stations and tankers at offshore moorings. Their site require-
ments for flat land are less stringent than those for other coastal projects
because they can be constructed in tiers. These terminals are used to
store either crude or processed products.

Employment: A large number of individuals are employed during
construction; the size of the labor force can vary considerably depending
on the number of tanks and the complexity of pumping systems. Approximately
565 workers would be needed to construct a facility capable of handling
250,000 barrels of oil per day [26]. To construct a 1 mil lion-barrel -
per-day storage terminal would require up to 900 workers. A storage
terminal may be built in phases, in which case, lower levels of con-
struction employment can be maintained for a number of years. Once the
terminal begins operating, very few employees are required to run the
facility. The staff includes maintenance and administrative personnel.

Induced Effects: During construction, wages will enter the local
economy at a significant level, and employment should draw on available
labor, especially at the unskilled level. Construction will be contracted
with a number of firms from both the local area and outside. The major
effect of a terminal after construction is unsightliness. The large
tanks dominating the coastal view may lower land values or slow down
price increases when compared with other areas. Examples of this potential
effect are terminals in Tiverton, Rhode Island, and Fall River,
Massachusetts. In Scotland, this potentially adverse effect was avoided
by locating the tank farms off the shoreline and behind large berms.

174

Effects on Living Resources

An onshore oil storage facility has the following characteristics
of particular concern to fish and wildlife: (1) oil storage tankers;
(2) usually a marine terminal with channels and a berth; (3) service
roads; (4) dikes; (5) cleared, level land; and (6) crude oil or petroleum
product transfer.

Location: Usually an onshore oil storage facility is closely
associated with another operation, such as an oil refinery or petro-
chemical plant. While a coastal location is not imperative for a storage
terminal, economics have generally dictated a waterfront site. The
ecological problems associated with such a facility usually concern
pollution of the adjacent waters , Thus many of the adverse effects to
fish and wildlife could be better controlled, or eliminated, by location
at an inland site.

Locations at the mouths of bays and estuaries would aid the flushing
and dispersal of silts stirred by boats approaching the facility and the
dispersal of petroleum discharges from engines and other sources. Channels
and harbors, which will require little initial and maintenance dredging,
should be considered as the best choices for the location of the facility.

Design: If a marine terminal is part of the facility design, then
effects on fish and wildlife will be minimized by using waterfront prop-
erty. This would avoid the loss of fish and wildlife habitat from the
filling of wetlands.

The need for adequate channels and a turning basin will cause
dredging problems of turbidity and sedimentation, which may lead to the
smothering of clams, corals, and other organisms. Oxygen depletion is
also associated with dredging. Channels should be designed to limit the
amount of initial and maintenance dredging. The channel route should be
the shortest distance to the facility for dredging with minimum disruption
of fish and wildlife habitat. The type of bottom material should also be
considered. Loose, unconsolidated material requires maintenance dredging
more often than does a solid substrate.

Construction: Open pile piers and floats should be built instead
of sheet steel bulkheads for marine terminals. In the construction
of steel bulkheads shores are often dredged to create a berth and to
obtain fill to place behind the bulkhead. This alters the natural
configuration of the shoreline and robs areas down the shore of needed
sand by interrupting littoral drift. In addition, solid fill structures

175

tend to intercept, divert, and disperse water currents. This diversion
may decrease available food supply and change water parameters, such as
salinity and oxygen, leading to a significantly altered fish and wildlife
habitat.

Oil storage facilities need to be relatively flat, and a major
construction component will be heavy equipment operations to level
the land. This requirement will result in the clearing of large
acreage and will cause a drastic change in the microclimate. Species
which previously occupied the sector will now find that area uninhab-
itable. Also, with the vegetation removed, erosion may occur if
appropriate control measures are not taken. Without proper con-
trol excessive sedimentation may occur in streams and rivers, pro-
ducing degraded fish habitats.

Operation: With the unloading of crude oil and loading of petroleum
products, spill prevention is the primary concern. During such operations
all vessels should be surrounded by an oil boom to contain any accidental
releases of petroleum until they can be removed by vacuum truck, oil
absorbing device, or other machinery. In case of an accident, automatic
shut-off valves can terminate the operation without excessive losses of
oil. The petroleum transfer must be supervised at all times, and a
contingency plan must be routinely practiced to allow personnel to
effectively react in time of an emergency.

Inspection of connecting hoses, seals, clamps, and other hardware
must be performed on a regular schedule, and equipment with any sign of
wear must be promptly replaced. Oil tankers must be inspected, and any
indications of corrosion or malfunctioning parts must be corrected
immediately.

Regulatory Factors

Construction and operation of oil storage complexes may require
Federal, state, and local permits and certification.

State and Local Role: State and local legislation and other actions
aimed at reducing the potential for adverse effects on the natural
environment in particular may be stimulated by the threat of location of
an oil storage terminal outside present ports and centers of industry.
As with regulation of petrochemical industry construction discussed in
2.4.2 and of refinery construction discussed in 2.4.1, state and local
governments may delay or block construction of new oil storage terminals.
Zoning laws and state utility regulations are examples of potentially,
important land-use control mechanisms which can serve essential pollution
abatement roles. This type of regulation may also impose design require-
ments on project components, such as clearing, grading, soil erosion,
geologic structure, amount of impervious surfaces, and landscaping.

176

state permits regarding water and air quality may also be required
for construction. In addition, separate or extended permits may be
needed for operation and maintenance activities.

Federal Role: Federal permits may be required for activities
affecting water and air quality at both the construction and operation
stages of development. Activities regulated may include channel dredging,
wetland alteration, and pipeline design and location. Dredge and fill
activities for channels or wetlands are regulated by the Corps of Engineers
under Section 404 of the Federal Water Pollution Control Act Amendments
of 1972 and Section 10 of the Rivers and Harbors Act of 1899. The Fish
and Wildlife Service advises in this process, and if the Service objects
to Corps permit issuance, differences must be resolved between the Corps
and the Department of the Interior in Washington. Typically permits are
issued by the District Engineer with comment from the Field or Regional
office of the FWS. Pipelines are discussed in Section 2.2.4.

Other important factors associated with coastal locations for oil
storage terminals include the protection of endangered species habitat
and operating permits related to air and water pollution.

Development Strategy

An oil storage terminal is required whenever transportation of oil
between the production field and refinery involves shipment by tankers
and pipeline. The reason is that tankers move oil in bulk quantities
whereas production and refining processes handle oil volume at a fairly
constant rate. Only small amounts of storage are needed when production
feeds directly into crude oil pipelines that pump directly to refineries.
Thus, oil production in areas with refineries will necessitate little
storage in the field. Storage will be provided at the refinery— partly
of crude and partly of products after refining. Production in remote
areas will more than likely involve tanker transport and thus will
require oil storage terminals.

Oil storage terminals are planned in conjunction with offshore
pipelines and oil transfer terminals. Neither can be sited in isolation
since they are part of a total oil transportation system.

Planning for the location of an oil storage terminal begins when
the field development plans are mapped out. The route of the pipeline
to shore and the location of the terminal are chosen to minimize the
cost and logistics of constructing and operating the total transportation
system.

The volume of storage necessary for an onshore oil transfer terminal
depends on the production rate of the offshore field, the size of the
tankers served, the frequency of their arrivals, and the expected duration
of bad weather periods. Storage capacity should be sufficient so that

177

production from the field does not have to be curtailed and that a
tanker has a minimal lodging time. The more hostile the sea conditions
in an area, the larger the storage capacity needed.

178

2.4 PROCESSING AND MANUFACTURING PROJECTS

Pollution is a major concern of the petroleum processing and products
manufacturing industry. Transporation problems, land use, community
revenue problems, and the psychological effects of intrusion can also
create difficulties in selecting a site. Few communities want a refinery
or petrochemical plant because one or more of these problems is attributed
to these facilities. Fortunately, existing infrastructure can handle
much of the facility needs created by anticipated OCS oil and gas recovery
in frontier areas.

The processing and manufacturing projects presented in this section
are:

2.4.1 Refineries

2.4.2 Petrochemical Industries

2.4.3 Gas Processing

2.4.4 Liquefied Natural Gas Processing

179

2.4.1 Refineries

A refinery converts crude oil into useful petroleum products such
as gasoline, fuel oil, and residual oil which is used by electric utilities.
A refinery uses a series of processing units that separate crude oil by
fractionation (distillation), convert it to other more valuable hydrocarbon
compounds, treat it to remove undesirable constituents, and then blend
basic stocks into more desirable end products.

Refineries are built in response to availability of crude and
demand for refined products (see Figure 38). Since it is easier and
less expensive to haul large quantities of crude in one extremely large
tanker than to carry refined products in smaller tankers, refineries are
usually located as close as possible to the center of demand (market
area).

Figure 38. Refinery, project implementation schedule.

INVESTMENT COMMITMENTS:

Site Purchase

Site Option(s) Taken

YEARS"'"

Start of

Construction

Begin
O Refinery
Operations

Acquisition of Use and
Location Permits

Operating Permits

Preconstruction Permits
(Includes EIS)

PERMIT ACQUISITIONS:

180

Table 17 illustrates the refining capacity, by state, in each of
the six principal U.S. refining regions. It is interesting to compare
refining areas to both established producing areas and to markets.

Refineries and offshore development do not correlate directly; a
refinery is not required in the frontier area onshore to serve the
offshore development. Therefore, investment to construct a refinery is
likely to be separate from other OCS-related development. While the
effects of substantial onshore development to support an offshore field,
and of constructing and operating a refinery are individually substantial,
the composite effect of both refineries and onshore support at a single
site would be much greater. The probability that both types of development
would occur together in the same place, however, is remote.

Description

The modern refinery consists of highly automated process units
which physically and chemically alter all or part of the crude oil
stream. In addition to the processing units, a refinery has a network of
pipes and pumping stations, storage tanks for crude and product, wastewater
treatment facilities, LNG storage tanks, and ancillary buildings (e.g.,
administration, machinery shop, fire station, warehouses, and truck
loading terminals). Pipelines enter the refinery from oil storage
terminals and leave the refinery to go to other oil storage terminals
(2.3.6). The refinery is always surrounded by a buffer zone for safety.

Due to their large demand for cooling water, most refineries have
large clarifiers to clean up water used in their cooling towers and
other parts of the refining process. Collection and treatment of other
wastewater necessitates rather extensive storm water and process water
systems. Storm waters, if necessary, are treated in aeration ponds
before discharge as they may have picked up contaminants. All process
waters pass through oil separators and aeration ponds before discharge
to surface waters.

In the "lower-48," refineries will all have railroad spurs for
delivery of materials and heavy equipment during both construction and
operation. Coastal refineries will usually have barge and tanker terminals.
Electrical power substations onsite will step down the line voltage for
use in the refinery.

Site Requirements

The siting requirements for a new "grass roots" refinery are extensive,
Acceptable sites must meet locational criteria with respect to the
market to be served, to existing oil industry infrastructure and to
transportation access; and a site must meet rather stringent requirements

181

Table 17. Capacity of Principal United States Refining Regions (as of
January 1976) - Exclusive of Hawaii and Alaska, United States maximum
is 15.5 million barrels per day (Source: Reference 42)

Maximum

Percent of United

Capacity

States Mainland

Region

States

(barrels/day)

Refi

ining Capacity

GULF COAST

Alabama

53,000

(38.

.5% in Texas

Mississippi

346,842

and

Louisiana)

Louisiana

1,827,031

Texas

4,144,778

TOTAL

6,371,651

41 .1

MID CONTINENT

Oklahoma

Kansas

Missouri

559,719
468,940
108,000

TOTAL

1,136,659

7.3

NORTH CENTRAL

Illinois

Indiana

Kentucky

Ohio

Michigan

Wisconsin

Minnesota

1,232,958
561,160
169,500
614,500
151,395
46,800
223,905

TOTAL

3,000,218

19.4

MID ATLANTIC

New York

114,500

COAST

New Jersey

Pennsylvania

Maryland

Delaware

Virginia

562,764
796,415

31,211
150,000

55,000

TOTAL

1,709,890

11.0

PACIFIC COAST

Cal ifornia
Washington
Oregon

1,993,503

383,105

14,737

TOTAL

2,391,345

15.4

MOUNTAIN

North Dakota

Montana

Wyomi ng

Colorado

Utah

New Mexico

60,163
164,016
194,557

65,000
158,878
106,305

TOTAL

748,919

4.8

182

with respect to water availability, the elevation and slope of the site,
and its foundation characteristics.

The desired location for refineries is as near to the product-
demand center as possible. By centrally locating a refinery, numerous
products can be distributed with a minimum of transportation difficulty
and expense, and bulk shipments of crude oil can be received and shipped
in large tankers. This means that refineries are usually located in
proximity to urban (and oil consuming) areas. Air, water, and noise
pollution standards may, however, cause refineries to locate in under-
developed rural areas near a city and not within the urban area itself;
the city may have already exceeded ambient air quality levels allowed;
this would preclude construction of any new refineries.

A refinery in actuality is located on a line between its source of
crude and its market so as to assure that the oil moves in one direction
and incurs a minimum of back-hauls. Transporting oil to a distant
refinery and then transporting products back to the region is usually
economically infeasible.

Coastal refineries are usually located several miles inland from
the coastline because property is usually cheaper and the chances for
storm damage are decreased. They are, however, usually sited adjacent
to deep navigable waterways because some crude end products (petroleum,
coke, boiler ash, natural gas liquids) will be transported to and from
the refinery by smaller tankers and barges. Examples of this are the
natural gas liquids--extracted from raw gas at gas processing plants--
which are used in gasoline manufacture. Petroleum, coke, and boiler ash
may also be transported on barges.

A site near water is also needed because a refinery has extensive
cooling water requirements. Approximately 4.5 million gallons per day
will be consumed by a refinery processing 250,000 barrels per day [26].
Gulf Oil's Alliance Refinery, a 200,000-barrel-per-day unit, uses much
more water. It requires 28 million gallons per day for cooling with 4
million gallons per day lost due to evaporation. In addition,
refineries require another 2 million gallons per day for process water.

A new refinery has rather extensive acreage requirements. An
acceptable site must include from 500-1,500 acres [43]. The Bureau of
Land Management estimates 1,200 acres is needed for a refinery [21].
Gulf Oil's Alliance Refinery (200,000 b/d) is on a 700-acre site.

A new refinery requires level land that is above the flood zone and
possesses soil-bearing capacities capable of supporting heavy structures
such as retorts, fractionating towers, pumps, and catalytic cracking
structures. Support for these heavy structures can be provided by
piles, but there must be a firm formation into which the piles can be
driven.

183

Level land is essential because it reduces the amount of earth
work involved, reduces the complexity of piping systems, and reduces
the pumping requirements within the refinery.

Refinery sites also require good transportation access. Trans-
portation access is even more important during construction than during
the operational phase, because thousands of tons of heavy materials such
as cement, piping, pumps, and heavy prefabricated steel vessels must be
brought in. Access by both barges and railroads is preferred. Access by
one of these is absolutely essential. Good road access is also needed
to handle the large number of vehicles during construction and the 200-
400 workers during the operational phase.

A refinery site must have access to large quantities of electric
power. Purchased electric power provides most of a refinery's power
with a per-barrel-use of 2 kilowatt-hours for a simple refinery to more
than 9 kilowatt-hours for a complex facility. It is estimated that
100,000 kilowatt-hours per day would be used by a 250,000 barrel -per-day
refinery [26]. Some refineries may produce their own electric power.

In the United States, many refineries use natural gas as a refinery
fuel rather than using a part of the input oil as fuel. Gas is cleaner,
is easier to handle, and requires less expensive equipment. If gas is
to be used as fuel, the site will need to be near a gas pipeline.

Lastly, a refinery is not sited in isolation, but is sited so as to
fit into a petroleum producing, transporting, and distribution system.
The best site, therefore, is one that fits into the existing petroleum
industry infrastructure as well as the infrastructure system that will
evolve in the future.

Construction/Installation

The construction of a large refinery will require approximately
three years [26] during which it will employ approximately 3,000 workers:
welders, pipefitters, electricians, equipment operators, and laborers
[25].

The entire site will probably be cleared of vegetation to allow
extensive grading and earthworks operations. Dikes will be built around
all storage tanks and in refining areas. Stormwater and process water
collection systems will be installed necessitating considerable trenching.
Wastewater treatment facilities consisting of aeration and retention
ponds will be excavated and diked. Parking lots will be graded. Finally,
the refinery site will be landscaped to improve its appearance.

Construction of the refinery process units, piping, and storage
tanks will require a great deal of metal bending, cutting, and welding.
After units have been fabricated and connected, they will be sand blasted,
cleaned with chemicals, and painted.

184

Numerous foundations for smaller buildings such as the operations
center, fire station, and administration building will be dug with
standard backhoes and trenchers. The buildings involve standard
construction methods.

Barge and tanker terminals often will be installed by marine
construction companies subcontracting to the main contractor. Jetties,
piers, pilings and dolphins will be installed using barge-mounted equipment
such as pile drivers and derrick cranes. Shorelines and bottom
modification may take place in the area of the terminal, with the
possibility of ajccommodating supertankers which would require water
depths of 60 to 90 feet.

Operations

Refineries produce a number of petroleum products by physically and
chemically altering all or part of the crude oil stream. The system is

actually a series of complex units, depending upon the number and char-
acteristics of the desired products.

The crude oil arrives at these highly automated facilities by
pipeline or tanker and is stored. When it enters the production stream,
it may undergo as many as four distinct processes: separation into
light, intermediate, or heavy hydrocarbon groups; conversion, which
chemically alters the groups into more refined groups (includes polymer-
ization, catalytic reforming, and cracking); treatment, which removes
the odorous contaminants such as hydrogen sulfide; and blending, which
mixes base stocks to produce a wider variety of products.
After processing, the products are stored for later distribution by
pipeline, ship, barge, or truck.

Community Effects

A refinery has the following characteritics of particular community
interest; a large parcel of land, high employment, high investment, high
service requirements, air pollution, and high requirements for water.

Employment: A refinery is the largest employer of the fifteen OCS
projects during the construction phase. One study estimates the average
work force to construct a refinery handling 200,000 barrels a day would
be 1,800 persons with a peak force of 2,900. Further, 1,000 members of
the peak level work force fall into skilled labor categories [28]. A
project of this scale would attract many new or temporary residents
unless it occurred near a major metropolitan area.

The operating staff for a refinery this size is approximately 550
persons. Subdividing this total, 55 are administrative support, 440 are

185

Figure 39. Example:
Reference 44).

refinery flow scheme (Source:

RihmKd goulliM

involved in operation and maintenance, with 396 of that total in the
skilled labor category; and 55 are in a specialized support category,
which includes laboratory and safety. The annual payroll for this
facility would be 6.8 million dollards [28].

Induced Effects: Construction and operation of a refinery have
several substantial effects on an adjacent community. While a major
city would be little affected by this project, a small community could
be totally disrupted. For the smaller community, the effect would be
that of a "boom town" with a rapid influx of construction workers liv-
ing in trailers or other temporary housing after all available units
are occupied. Most of these workers will move on after the refinery
is constructed, but substantial costs to the community will remain
unless other local opportunities induce these individuals to remain in
the area. The temporary residents will require services such as schools,
protection, and water and sewerage, which will tax the financial structure
of the community during their short residency. By contrast, the full_
level of taxable income from the refinery will not be forthcoming until
it is operating.

186

After a refinery becomes operational, the total number of employees
declines but is still a significant total for almost any community to
absorb. Wages coupled with the number of new residents will greatly
alter all aspects of community life. Pressure for construction of
residential and commercial buildings will be intense. New public
facilities and services will need to be provided as rapidly as possible.
In some cases, temporary facilities and services should be considered in
an attempt to coordinate the community investment level to the permanent
employment level [45] rather than the peak construction employment level
(2,900 to 3,000).

The refinery could affect the water supply of the community. With
such large water requirements, surface and subsurface patterns could be
altered. The community will also be concerned about possible contamination
of local supplies and effects on recreational resources adjacent to the
refinery.

An additional community concern is air pollution. Emissions and
odors are potential problems associated with refineries. Therefore, in
influencing the selection of a location, the community will encourage
the refinery to locate downwind, from any large settlements or heavily
used recreation areas.

Effects on Living Resources

A refinery has the following characteristics of particular concern
to fish and wildlife: (1) often a coastal location, usually on the
waterfront; (2) large acreage of cleared, level land; (3) deepwater
marine terminal; (4) navigation channel, berths, and turning basins; (5)
offshore/onshore pipeline; (6) crude oil processing and storage equipment;
(7) large amounts of cooling water; (8) access roads; and (9) potential
for air and water quality problems.

Locations: Improperly located refineries and related facili-
ties can have serious impacts on coastal water, as well as on air
and aesthetic resources. For example, a 250,000 barrel -per-day
refinery would require at least 4 million gallons per day of
fresh water and would generate a variety of pollutants into the
water that must be treated. The waters may contain oil and
petroleum products, heavy metals, and process chemicals, which can
can cause oxygen depletion, sedimentation, salinity changes, and
toxicity.

In planning a refinery the sponsor usually desires to situate
the facility as near the shorefront as possible to provide access to
Very Large Crude Carriers (VLCC) or as large a vessel as possible and to
provide a source of cooling and process water. It is not imperative to
locate the facility on the shore because the crude oil, the end products.

187

and the needed water can be piped. Economics have generally dictated
their presence on the waterfront.

Usually a refinery is closely associated with other operations,
such as oil storage facilities or petrochemical plants. The ecological
problems associated with such facilities usually concern pollution of
the adjacent waters, thus many of the adverse fish and wildlife effects
could be better controlled or eliminated by location at an inland site.

Location of marine terminals at the mouths of bays and estuaries
would aid the flushing and dispersion of silts stirred by boats approaching
the facility and of petroleum discharges from engines and other sources.
Channels and harbors that will require as little dredging as possible
should be considered as the best choices for the location of the terminal.

Relatively flat land is needed for the installation of refinery
processing equipment. With level, shorefront land zoned for industry at
a premium along the coast, the chances increase that wetlands will be
filled to obtain the desired elevation. If this is done, important
spawning/breeding and rearing areas of a variety of fish and wildlife
will be lost. In addition, water circulation currents will be altered,
perhaps leading to changes in parameters such as salinity, temperature,
oxygen, etc.

Design: The need for adequate navigation channels and a turning
basin will cause dredging problems of turbidity and sedimentation, which
may lead to the smothering of clams, oysters and other sessile organisms.
Oxygen depletion is also associated with dredging. Channels should be
designed to limit the amount of initial and maintenance dredging. The
channel route should be the shortest distance to the facility for dredging
with minimum disruption of fish and wildlife habitat. Also to be considered
is the type of bottom material, with loose, unconsolidated material
requiring maintenance dredging more often.

With the need to service large tankers, the selected deepwater site
will need ample space to allow maneuvering of the large ships, including
turn-around capability. To reduce the chance of accidental oil spills,
a fail-safe transfer system should be employed to keep human error to a
minimum. A sophisticated monitoring system, which not only records
unloading operations but gives indications of possible trouble sources,
should be incorporated into the design.

With the possibility that crude oil tankers would be situated in
deep waters distant from shore, provision should be made for general
boat traffic to pass safely and easily without having to travel around
the end of the pier. This will reduce the potential for boating accidents.
The pier design should utilize open piles and avoid a solid-fill structure.
The latter type alters the natural configuration of the shoreline and
robs areas down the shore of needed sand by interrupting littoral drift.

188

In addition, solid-fill structures tend to intercept, divert, and disperse
water currents. This may decrease available food supply and alter water
parameters, such as salinity, oxygen, etc., which leads to a significantly
changed fish and wildlife habitat.

If the refinery is to be located in a coastal site, the facility
design should incorporate features to minimize intrusion upon nearby fish
and wildlife habitats. Access to the plant should be via existing
service roads with upgrading to allow for heavy equipment, but roads
should not be open to the general public. Buffer zones, especially of
evergreens, can protect wildlife from visual and noise intrusions into
the habitat.

Dikes around the storage tanks should be high enough to hold all
the contents of the tank if it should rupture. Every tank must have
access by a service road to allow safe and effective fire protection.
Dikes should not be routinely traversed by vehicles, and the top of a
dike should not be utilized as a service road.

Construction: The sponsor must perform the coastal construction in
a careful manner to protect adjacent aquatic and terrestrial areas. The
scheduling of construction must avoid sensitive periods of species,
including breeding/spawning, rearing of young, etc. Operation of heavy
equipment must be performed to protect fragile environments, such as
barrier beaches, wetlands and clam/mud flats. In many cases, parti-
cularly near wetlands, mats can reduce the impact of heavy equipment
operations. Construction must involve stringent erosion control methods
to prevent silt from entering streams and rivers where they could interfere
with fish reproduction.

The need for flat land will cause large acreages to be cleared of
vegetation and will cause a drastic change in the microclimate of the
area. Species which previously occupied the sector will now find that
area uninhabitable. Also, with the vegetation removed there is the
possibility of erosion if appropriate measures are not taken to control
it.

If the offshore/onshore pipeline is not suspended on a pier or
piles, laying a pipe to shore will cause environmental impacts from the
dredging needed to bury the pipeline (See Section 2.2.4).

Operations

The applicant's major environmental problem in operation will be in
meeting pollutant discharge standards on industrial waste disposal and
runoff water. The problems of oil spills are related to both the refinery
and the transport of crude and refined products. The discharge of crude
oil and petroleum products into estuarine and coastal waters presents

189

special problems in water pollution abatement. Oils from different
sources have highly diverse properties and chemistry. Oils are relatively
insoluble in sea and brackish waters, and surface action spreads the oil
in thin surface films of variable thickness, depending on the amount of
oil present. Oil, when absorbed on clay and other particles suspended
in the water, forms large, heavy aggregates that sink to the bottom.
Additional complications arise from the formation of emulsions in water,
leaching of water soluble fractions, and coating and tainting of sedentary
animals, rocks, and tidal flats.

Wildlife that become involved with an oil spill can die from ingestion
of the petroleum or from loss of insulating capacity of their feathers
or fur. Vacuum trucks and other skimming devices should be employed to
remove any collected oil. Any damaged vessels, which transport petroleum
products, should have an oil boom placed around them when necessary to
prevent discharge into the water while repairs are being performed.

For refineries, problems with operations are by far the most important
consideration affecting fish and wildlife resources and the consideration
that the applicant will give the most effort to solving. If sited on
the waterfront, designing the facility to avoid shoreline wetlands, and
estuarine disturbances, particularly of wetlands, will be next in order.
With the necessity to handle flammable gases and petroleum hydrocarbons,
operation of the refinery must be performed to prevent accidental releases
and ignitions so as to protect human and wildlife environments. In addition,
emergency procedures should be practiced routinely so personnel can
respond quickly and appropriately in time of need.

Regulatory Factors

Refineries are likely to be subject to special siting procedures at
the state level. Local ordinances designed to minimize impacts on the
natural environment may also be stimulated by refinery siting proposals.
Federal regulations for dredge and fill and operating standards for air
and water pollution are also important.

State and Local Role: State regulatory authorities may exist with
the ability to override or supplement local regulatory controls over
refinery siting. These controls are analogous to the zoning controls
referenced in Section 2.1.3. Local reaction to these proposals is often
adverse, and sponsors have been frustrated in many recent attempts as
illustrated by Table 18.

Federal Role: If the refinery does not use a coastal location
requiring dredge and fill or water access, federal laws will primarily
influence design and operation of air and water pollution abatement
devices.

190

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Development Strategy

From the standpoint of the major oil companies and independent
refinery companies, who own refineries, the most critical factor affecting
the establishment of a "grass roots" refinery is the massive capital
investment involved. At a cost of $1,500 to $3,000 per barrel -per-day
capacity, depending on location and complexity [26], a new 200,000
barrel -per-day refinery can cost from $300 to $600 million. Such quantities
of money represent large investments even to the larger oil companies.
Money for a new refinery can be generated from company profits or by
selling stocks and bonds.

The second most important factor affecting the decision to construct
a new refinery is the considerable length of time before an investment
in a refinery can begin to earn a return. This is especially critical
when oil markets become unstable, for approximately four years are
required to construct a refinery. If during this four year period the
market changes significantly, the refinery can end up being a poor
investment.

If construction of a new refinery were necessary, the petroleum
company would attempt to find a site within the existing industry infra-
structure or within an area that already was being developed by the
petroleum industry. The company would employ this strategy in order to
minimize time spent in obtaining necessary dredge-and-fill zoning, and
other permits.

Sufficient instabilities and changes have occurred in petroleum
markets in the last few years to indicate that there nay be reluc-
tance to invest in new domestic refineries. The most important
instabilities, though, have been introduced by fluctuating interest
rates and inflation. If both shoot upward in the midst of construction,
the cost of completing a refinery can jump by tens of millions of dollars.
These instabilities cast long shadows on the security of investing in
hundred-million-dollar refineries and may herald a slowdown in new
refinery construction.

Oil refineries are built in response to growing demand. There is,
of course, some attrition of refining capacity as refineries get obsolete
or inefficient; but the attrition rate is low, so new refinery construction
is justified almost entirely on the basis of growth in demand.

If demand for products is growing slowly, it is usually more feasible
to add refining capacity than to construct a major new refinery. First,
a smaller investment is required, and its payback is faster. Secondly,
the addition of a large increment of refining capacity in a region may
either cause marketing problems for additional output or require the
shutdown of older, yet functional, refineries.

192

Expansion of existing refineries is less expensive, since in most
cases a significant portion of the infrastructure at an existing refinery
can be utilized and land will already be owned.

The infrastructure-- the crude end product pipelines, tanker and
barge terminals, storage tanks, and even technical know how--are extremely
important in favoring construction in refining regions. If a refinery
is to be constructed in an area without refineries, the refinery and the
required infrastructure would have to be built, thus pushing costs
higher.

New refineries will probably not be built in response to OCS finds
because (1) offshore production rates will more than likely not sustain
a refinery; (2) refineries are usually built in market locations and
depend on demand growth there; and (3) any OCS production can simply
displace foreign oil which is presently being refined in coastal regions.

193

2.4.2 Petrochemical Industries

A recent survey revealed that 622 petrochemical plants are operating
in the United States; 22 percent of them are located in Texas. There
are approximately 100 major petroleum refining and petrochemical plants
in Louisiana, making that state one of the principal producers in the
United States. A number of facilities in Louisiana are among the largest
of their kind in the world. The most important reason cited for the
growth of the petrochemical industry in Texas and Louisiana is proximity
to raw materials. Other factors influencing the development of this
industry have included the availability of existing facilities (see
Figure 40), transportation, labor, land, and markets [47].

Figure 40. Petrochemical industries, project implementation schedule.

INVESTMENT COMMITMENTS:

Site Purchase

Site Option(s) Taken
YEARS •••

Acquisition of Use and
Location Permits

Start of
Construction

Begin
O Processing
Operations

Operating Permits

Preconstruction Permits
(Includes EIS)

PERMIT ACQUISITIONS:

The petrochemical industry has undergone dramatic growth
and profit in recent years. The most important product group
organic chemicals, the basic materials from which synthetic fi
plastics, rubber Jubricants, and hundreds of other products a
Petrochemical industry sales in 1970 totalled almost !^20 billi
one-third of the total chemical industry sales. Employment e
300,000 and its value-added approximated $10 billion, which is
twice that of the petroleum refining industry. Primary organi
chemicals, those whose manufacturing operations tend to locate
"feedstock" (raw materials) sources, had a sales value of $7.4

194

in capacity
is industrial
bers and
re made,
on, about
xceeded

more than
c petro-

close to

billion [48],

Description

Petrochemicals are c
(e.g., naptha) and natura
from these raw feedstocks
olefins and aromatics. (
energy products such as g
lubricating oils, as well
petrochemicals are furthe
and chemical stages into
dyes, resins, and fibers)
paints, textiles, rubber,

hemicals derived from refined petroleum products
1 gas liquids. The chemicals directly produced

are classified into two main categories--
Excluded from the definition are all fuel and
asoline, fuel oil, natural gas, kerosene,

as asphalt, wax, and coke.) These basic
r processed through several intermediate mechanical
a wide range of chemical derivatives (such as
, from which many end products are made including

plastic products, and many others [48].

Several hundred petrochemicals can be identified. The six petro-
chemical groups underscored below are those which were produced in the
greatest quantities in 1970. Among the specific types produced are
[45]:

aromatics

formaldehyde

benzene

perchloroethylene

trichloroethylene

vinyl chloride monomer

polypropylene

polyisoprene rubber

polybutadiene

polyisoprene

high density polyethylene

ethylene

low density polyethylene

synthetic glycerine

ethylene oxide

orthoxylene

styrene monomer

sulfurized fatty bases

oils

additives

leaded compounds

neoprene rubber

chloroprene monomer

isopropyl alcohol

acetone

metaxylene

paraxylene

ammonia

propylene oxide

ethane

hydrogen gas

nitrogen

argon

toluene

A "petrochemical complex" is virtually undefinable as a physical
entity but it is often an industrial area of large size, perhaps 300 to
400 acres or more. Of course there are many smaller manufacturers
producing special products. A petrochemical plant has a "refinery look"
to it. There are tanks, pipes, stacks, and metal buildings.

Site Requirements

A minimum of 300 acres is currently required for a complex able to
support, for example, 1 billion pounds of olefins production per year.
This may be representative of future petrochemical development that

195

would occur in regions where currently there is a minor amount of petro-
chemical manufacturing. These complexes would be tied largely to refinery
development and would include plants producing those primary organic
chemicals and key derivatives that are typically manufactured close to
feedstock sources for economic reasons. Although the trend towards
integrated refineries and petrochemical complexes will tend to decrease
the net land requirements, this should not offset other pressures for
more land. It is assumed that land requirements in the more crowded
Mid Atlantic area will stay the same as more land-efficient installations
are used there. The future land requirements for a petrochemical complex
by region are assumed as follows [48]:

Region Acres

Required

New England 330

Mid-Atlantic 300

South Atlantic 350

Puget Sound 350

San Francisco Bay Area 300

Construction/Installation

Typically a petrochemical complex must be situated on solid soils
of high load-bearing capacity because of the many activities involving
heavy equipment. With its location usually in a coastal region there is
a good probability that wetlands will be involved at some point in
construction. The land must be cleared of vegetation. Unstable land must be
excavated and filled with either sand or gravel to maintain an acceptable
working surface.

The construction of a petrochemical complex will require land
clearing, grading and earth-moving operations, construction of storage-
tank dikes, access roads, and parking areas. If the site is only slightly
above water, considerable dredging and filling may also occur to raise
the elevation of the site. These various operations will all require
the use of heavy construction machinery such as bulldozers, drag lines,
and graders.

Installation of the processing equipment, storage tanks, foundations,
pipelines, and pumping and electrical systems requires skilled welders,
pipefitters, electricians, carpenters, and heavy equipment operators.
Several hundred workers would be needed to construct a large facility.

Petrochemical complexes would normally be constructed by a consortium
of construction companies, each of which specializes in a certain type
of work. One company may do most of the earth work, such as grading and
foundations; another will fabricate the tanks and install the piping and

196

electrical networks. These subcontracting companies will work for a
principal contractor who often designs the facilities and then inspects
and supervises the construction. The principal contractor is responsible
to the sponsor which is usually one or a group of companies.

Operation

Current water requirements for a representative complex approximate
24 million gallons per day (Table 19). Water requirements should decrease

Table 19. Estimated Water Requirements for a Representative
Petrochemical Complex (Source: Reference 48)

Plant

Annual Output
(Million lbs)

Current Makeup

Requirements

(Millions GPP)

Orthoxylene
Toluene )
Xylenes >
Benzene /
Styrene
Ethyl benzene

139

2150

380
87

0.4

1.8

3.0
0.5

Ethylene
Propylene
Butadiene I
Butyl ene /

1560
194

6.0
0.5

Cumene
Phenol
Acetone;

520

0.8

Polyethylene

Ethylene Glycol

Vinyl Chloride Monomer

Polypropylene

Oxo Alcohols

Acrylonitrile

Cyclohexanone

90
200
500

70
245
100
237

0.3
1.6
4.0
0.2
1.3
1.9
1.6

TOTAL

6472

24 (approx.)

197

as industry becomes more efficient in using water, but should still be
significant. Engineering contractors and industry sources indicate that
a 50 percent reduction in water requirements should be achieved by 1985
[48].

Community Effects

A petrochemical plant has the following characteristics of particular
community interest: (1) a large parcel of land; (2) high employment;
(3) high investment; (4) high service requirements; (5) air pollution;
and (6) water requirements.

Employment: Employment characteristics for construction and operation
re similar to refineries, discussed in Section 2.4.1. In each case, a
large construction force is required. After construction the employment
level drops, although the plant is a major enterprise in terms of people
employed and wages generated.

Induced Effects: Petrochemical plants and offshore development do
not directly correlate. Production in an offshore field does not
automatically indicate development of a petrochemical plant onshore.
Therefore, construction of a petrochemical complex can be quite separate
from the OCS-related projects described in this part of the report.

Effects on Living Resources

A petrochemical plant has the following characteristics of particular
concern to fish and wildlife: (1) large amount of cleared, level land;
(2) coastal location; (3) location near the source of raw material
refined products; (4) air and water pollution potential; and (5) require
lat^ge amounts of cooling and process water.

Location: In planning a petrochemical complex, the sponsor usually
desires to situate the facility as near as possible to a refinery. A
waterfront location is desired for marine access and for a source of
cooling and process water. It is not imperative to locate the facility
on the shore because the feedstock, products, and water can be piped. In
view of the pollution potential and other environmental risks associated
with a shorefront site, a non-waterfront location is desirable.

Sites adjacent to tidal streams, deadend harbors, small lagoons,
and similar small or poorly flushed water bodies should be avoided
because of their extremely limited capacity to accept and assimilate
even small amounts of contaminants.

It is often desirable to direct industrial development to those
areas which already have been modified and disrupted through existing
industrial development or other land alteration. If industrial development

193

must occupy new areas, ecologically vital areas should be avoided.
Sites such as dredge-spoil dumps which have had their ecological functions
obliterated, might conveniently be developed for industrial use, providing
any adjacent vital areas are preserved intact. It should be noted that
problems arise with expansion in committed areas that are designated by
the EPA as presently "air pollution impacts" and where new industry is
essentially banned in order to prevent further air quality degradation.

There are many reasons to locate chemical industries back from
water bodies and to provide for buffer strips of vegetation between the
facility and the water's edge. The vegetated area provides a visual
screen, a purification system for storm runoff, and a protective buffer
for the ecologically sensitive shoreline, especially the wetlands.
The setback should be placed above the annual flood line, which marks
the upper edge of wetlands, and should provide a buffer wide enough to
cleanse the maximum storm runoff it might receive in the 5 or 10-year
rain storm. Flood-plain management and flood-proofing requirements must
also be considered.

Design: The petrochemical plant's waste treatment needs must be
incorporated into the community's long-term plan for environmental
protection. For example, since the constituents of industrial effluent
are usually quite different from those of domestic sewage, separate
private systems may have to be constructed by the petrochemical plant
and planned accordingly. Where discharge is allowed into the municipal
collection network, private pretreatment units will probably be necessary
to reduce the industrial waste flow to domestic strength before discharge,
in order to protect the municipal facilities and the receiving waters.

Construction: The applicant must perform the site preparation with
the utmost care to protect adjacent aquatic and terrestrial vital areas
and generally productive habitats. Extra precautions will be necessary:
(1) to minimize the alteration of water systems; (2) to prevent the
erosion of soil; and (3) to eliminate the discharge of toxic or deleterious
substances. Excavation and filling of areas near wetlands must be done
so that sediments do not enter the wetland ecosystems. Revege-
tation of disturbed areas must be accomplished as soon as possible
to reduce erosion.

Operation: The applicant's major environmental problem in operation
will be in meeting pollutant discharge standards on industrial waste
disposal and runoff water (Table 20). The problems of oil spills arise
with both petrochemical plants and refineries. Unfortunately, the
location of these facilities is such that spill and leak impacts are
heaviest in the rich and vulnerable water of estuaries. New facili-
ties should probably not be sited on bodies that have limited canacity
for flushing.

In operation, petrochemical plants require large quantities of
water for both cooling and processing purposes. Cooling water is used
to reduce the heat generated during manufacturing operations. It does

199

Table 20. Estimated Future Water Pollution Loadings of a Representative
Petrochemical Complex, in Tons per Year (Source: Reference 49)

(Best available
technology)

Annual —
Production Suspended
Plant (million Ib^l ROD COD Solids

Orthoxylene
Toluene )
Xylenes /
BenzeneJ
Styrene
Ethyl benzene
Ethylene
Propylene
Butadiene
Butyl ene
Cumene )
Phenol j
Acetone
Polyethylene
Ethylene Glycol
Vinyl Chloride
Polypropylene
Acryloni trile
Oxo Alcohols
Cyclohexanone

2289 23 228 0-1

467 18 875 6

1754 43 442 20

425

517

n/a

200

0-1

500

110

100

245

1071

237

111

0-1

not come into direct contact with the petroleum and is not thereby
contaminated. However, it does present potentially significant thermal
pollution problems and directly kills organisms sucked in with the
cooling water. In addition, land subsidence may be caused in certain areas
by excessive aquifer withdrawal.

Regulatory Factors

A petrochemical complex must comply with a complex set of air and
water pollution control criteria derived in part from Federal legislation
and in part from state and local programs. Site specific controls
related to dredge and fill, pipelines, water supply, and transportation
may also require permits or approvals from various public agents.

State and Local Role; State and local legislation and other
actions aimed at reducing the potential for adverse effects on the
natural environment in particular, may be stimulated by the chreat of
location of major petrochemical complexes outside present ports and

200

centers of industry. As with regulation of refinery construction discussed
in 2.4.1 and of oil storage terminal construction discussed in 2.3.6,
governments may delay or block construction of new petrochemical industries
and refined products pipelines through zoning laws and state utilities
regulations and water and air pollution abatement programs. The 1976
amendments to the Federal Coastal Zone Management Act of 1972 expand the
responsibility of state coastal planners in this field. With an approved
Coastal Zone Management Program, their plans may influence Federal
permit and licensing activity.

Federal Role: The Federal role in the location of petrochemical
industries is dependent on water access or alteration of wetland areas
regulated under dredge and fill statutes. Industry standards affecting
operations have also been specified under the air and water quality
programs pursuant to the Federal Water Pollution Control Act Amendments
of 1972 (PL 92-500) and the Clean Air Act. The primary Federal agency
involved, therefore, is the Environmental Protection Agency.

Development Strategy

Petrochemical development will be affected by a number of factors,
such as potential profit, feedstock availability, investment costs,
available labor skills, and a receptive political/environmental atmosphere.
Table 21 shows the relative ranking of six regions according to key
locational factors. On the East Coast, development in New England
should be minor with only a high OCS find yielding development of major
petrochemical facilities. The reason for this is the relatively low
level of expected refinery activity and the higher priority alternative
fuel uses of that refinery output. Development in the Mid Atlantic
should approximate the overall output percentage for petrochemical
feedstock use. This development should occur despite environmental
resistance because of the high market demand and attractive economics of
petrochemical production in the Mid Atlantic [48].

In the South Atlantic, substantial development could occur under
OCS development, exceeding tnat of the Mid Atlantic. The likely profit-
ability, greater availability of feedstock, land availability, and a
more receptive political /environmental climate should allow more signifi-
cant development in this area. On the West Coast, petrochemical development
should occur on a limited basis due to lower feedstock availability,
limited market demand in the Northwest, higher investment costs, and
potential political/environmental resistance. This should be more the
case for San Francisco than for Puget Sound. In fact, under high OCS
development, the latter area could become a net exporter of petrochemical
products to other western regions by the year 2000 [48].

201

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When a very large, rich gas find is made, a petrochemical (ethylene)
plant may be attracted to the area. Such a plant uses ethane produced
by the gas processing plant as feedstock. However, a gas find in a
frontier region would have to be extremely large in order for a petro-
chemical plant to become an economically feasible proposition.
Approximately 10,000 gallons per day of liquid hydrocarbons with a high
percentage of ethane would be required to support a billion-pound-per-
year ethylene plant. This large volume must also be sustained for ten to
fifteen years to justify the location of an ethylene plant. The establish-
ment of a large ethylene plant may induce additional downstream petro-
chemical activities to locate in the region [26].

203

2.4.3 Gas Processing

Offshore gas is obtained through a series of activities which
include: (1) the drilling and completion of wells; (2) separating and
dehydrating the raw natural gas into its constituent parts; (3) removing
hydrogen sulfide if present; (4) recovering sulfur from the gas; and (5)
storing and distributing the various forms of natural gas. These activities
vary according to the composition of the well stream, the size of the
producing reservoir, the proximity of the well to the shore and transmission
lines, and other factors.

Processing plants are required to treat and process natural gas by
separating methane out from the higher molecular weight compounds that
are associated with natural gas (See Figure 41). Methane is the valuable
component of natural gas. After separation, the gas goes through another
process to take out carbon dioxide, hydrogen sulfide, and other unwanted
consitutents. It is then transshipped to gas transmission pipelines for
distribution to local utilities or to other companies for further processing.

Figure 41. Gas processing, project implementation schedule

INVESTMENT COMMITMENTS:

Site Purchase

Site Option(s) Taken

Start of
Construction

YEARS •••

Acquisition of Use and
Location Permits

Begin
O Processing
Operations

Operating Permits

PERMIT ACQUISITIONS:

Preconstruction Permits
(Includes EIS)

204

Description

Gas processing plants are constructed if the offshore gas stream
contains a sufficient amount of recoverable petroleum liquids. Being
designed for the particular stream it processes, the plant may range in
capacity from two million to two billion cubic feet per day (cf/d). Gas
plants generally have a life of 10 to 20 years, depending primarily upon
the expected life of the producing reservoir. A gas processing plant
will have refrigeration units, compressors, power generators, a process
building and tanks for the storage of recovered liquid hydrocarbons.

When gas is produced on an offshore platform, some partial
processing of the gas stream usually takes place on the platform. If
both gas and oil are produced, a separator is needed so the oil and gas
can be metered and pumped through separate lines. If water is also
produced with the oil and gas, a tank to remove water which is not
contained in an oil-water emulsion is often used. For distant offshore
production in the North Sea, Gulf of Mexico, and Pacific Coast the
practice has been to separate free water and natural gas from the oil on
the platform and then pipe the oil-water emulsion and gas to an onshore
facility for treatment. When partial processing takes place on the
platform, additional costs are incurred since space on a platform is
much more expensive than it is on land, and additional space is required
for both crew and equipment. Thus the tradeoffs between the differential
cost of processing facilities determines the location of partial processing
facilities [26].

Site Requirements

Land, preferably flat and well-drained, is required for buildings,
storage facilities, pipes, towers, compressors, buffer zones, and
parking lots. Actual space required for processing is small; much more
space is required for safety reasons. The process, loading, utility,
storage, and office areas are usually separated, with extra land around
the plant perimeter. The amount of land required for a gas plant is
related, but not directly proportional to volume of gas handled per day.

Gas processing plants require sites of 75 acres or less, of which
10 to 20 acres may be intensively used for buildings and structures.
The remaining acreage is usually buffer zone. If necessary, partial
treatment facilities can be constructed on sites as small as 2 to 4
acres.

When capacity exceeds 600 to 700 million cf/d, an additional
processing unit is usually required , which takes up additional land. A
typical plant handling a billion cf/d might require a total of 75 acres,
of which 20 would be used for buildings and structures. A plant handling
200 million cf/d would require 50 acres [50].

205

Onshore partial processing facilities may be established to process
natural gas and/or oil. A combined partial processing facility requires
approximately 15 acres of land per 100,000 barrels of oil and associated
gas processed [26]. A gas processing plant must be sited somewhere
between the gas pipeline landfall and the commercial gas transmission
line. The availability of land along this route is a primary determinant
in plant siting, as are local land-use patterns and regulations. Pipeline
transportation costs increase the farther inland the gas plant is sited,
but this increase is usually out-weighed by the high cost of coastal
land [26].

In a gas/oil mixture, heavier hydrocarbons are removed from the gas
as quickly as possible after separation of the gas from the oil to
minimize the possibility of plugging up the pipeline. Plugging, which
reduces line capacity, is due to the condensation of hydrocarbons or the
formation of hydrates on the inside of the pipe. As a result, gas
processing plants and tank farms are situated close to each other and to
the pipeline landfall.

Cons tructi on/ 1 ns tal 1 ati on

The construction of a gas plant handling a billion cf/d would
require about $85 million (1976 dollars) in capital investment. This
would include condensate receiving facilities and full fractionation and
storage for propane, butane, gasoline, and condensate.

Environmental impacts vary with the site characteristics. If a
water front location is chosen, environmental disturbances may occur due
to dredging, filling, channel alteration, and spoil disposal. Inland
locations reduce these disturbances. Since no unique, heavy machinery
or processes are required on the site, site alteration and construction
are not expected to result in severe noise or air pollution.

Operation

The nature of onshore gas processing depends primarily on two
things: (1) the amount of ethane, propane, butane and other liquid
hydrocarbons present in the gas; and (2) the amount of water and hydrogen
sulfide (impurities) in the gas stream. An example process flow chart
is shown in Figure 42. In general, the gas is produced at an offshore
platform, partially processed to separate it from the oil and water in
the well stream, piped to shore, treated to remove impurities, processed
to recover valuable liquid hydrocarbons, and delivered to a commercial
gas transmission line [26].

If the gas produced offshore is associated with oil, the gas will
usually be separated from the oil and water on the platform by an oil-
gas separator. Water is removed from the bottom of the separator,

206

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207

treated and discharged to the ocean. At this point, the gas still
contains water vapor, which may be removed by dehydration on the platform.
Dehydration is necessary because water vapor in the gas stream may
freeze under pressure in underwater pipelines, interfering with the gas
flow. If only a small amount of associated gas is produced by a given
well, the gas may be reinjected into the formation in order to maintain
pressure and permit recovery of oil resources [26].

The water demand for gas processing plants may reach 750,000 gallons
per day, but most plants use less than 200,000 gallons per day. A
typical plant uses about 1.5 gallons of water per thousand cubic feet of
gas processed. The total water requirement for a gas plant varies
depending on the cooling process used, with an air-cooled system requiring
much less than a water-cooled system. When available, water is usually
obtained from the nearest municipal water system.

A gas plant handling a billion cf/d would have an average demand of
7,500 kilowatts. Electric power will usually be purchased from a local
utility or generated at the gas plant [26].

Gas plant products are transported by rail, truck, pipeline, or
barge, depending upon what type of transportation is available and the
location of markets for a particular product.

Cormiunity Effects

Gas processing plants occupy 50 to 75 acres and are located near
the coast but not necessarily adjacent to the shore. These plants,
which are usually located in rural areas, include buffer property for
safety purposes and add to the employment base.

Employment: One recent study estimated that construction of a gas
processing plant handling 300 million cubic feet/day requires 250 con-
struction workers and 50 engineers [19]. A larger plant, with a capacity
of one billion cubic feet/day, would employ a maximum of 550 workers
during the construction phase [26]. After completion, a gas processing
plant is relatively mechanized. A plant handling 300 million cubic
feet/day might employ 21 persons: including 2 supervisors, 5 technicians,
8 operators, 5 maintenance persons, and 1 contract service person [26].

By contrast, a larger plant, processing 1 billion cubic feet/day,
might employ 35 people. In the smaller plant, monthly wages for all
employees would be $27,000. Of the employees, 60 percent would be hired
locally; experienced supervisors and technicians would be brought from
other areas. The employees who would be new residents would be those
with higher wages. They will require homes and services in the local
area.

203

Induced Effects: Induced effects from new employees moving into
the area, approximately 15 individuals, would be slight and probably not
noticeable in the local economy.

The facility will be located in a rural area for safety reasons.
The adjacent community may need to provide services which include extending
sewage lines, constructing new access roads, and other costly changes.
Water demand for the facility may disrupt supply to other users from
surface sources or alter the water table in small areas. The rural
areas used by processing plants are usually unprepared for industrial
growth. As part of a zoning change or building permit issuance, the
local government may require the company constructing the plant to fund
these improvements either jointly with the community or alone.

Effects on Living Resources

A natural gas processing plant has the following characteristics of
particular concern to fish and wildlife: (1) offshore/onshore pipeline;
(2) pipeline landfall; (3) gas processing equipment; (4) coastal site;
(5) relatively level topography; and (6) access roads.

Location: The ecological problems related to a natural gas
processing plant are primarily a result of the sponsor's desire to
locate the facility at a coastal site on the pipeline which trans-
ports gas from offshore fields to onshore. The location is sought
because costs can be reduced. Although a relatively small amount of
land is needed for the facility, appropriate coastal land along the
pipeline route is difficult to find. Efforts should be directed toward
siting the plant on existing land rather than toward filling of wetlands
to provide a location for the facility. The latter course of action
will destroy important spawning/breeding and rearing areas of a variety
of wildlife. Additionally, water currents will be altered, leading to
changes in salinity, temperature, oxygen, etc.

Planning the coastal location becomes more complicated when the
pipeline landfall is considered. Pipeline landfalls should be avoided
in vital habitats, such as barrier beaches, dunes and sea cliffs, and
endangered species habitats.

Locations of gently sloping topography where the terrain changes
quickly from ocean/estuarine to upland are desirable. Many of the above
complications in siting a gas plant can be avoided or reduced by placing
the plant on upland areas rather than coastal. Pipeline corridor siting
is of vital concern because construction through fish and wildlife
habitat, especially in wetlands, may bisect the area. This may cause
changes in water circulation and water salinity. Also, with the new
water flow the area becomes susceptible to erosion and loss of vegetation
from fast moving currents.

209

Design : If the gas processing plant is to be located in a
coastal site, the facility design should incorporate features to
minimize intrusion upon nearby fish and wildlife habitats. Access
to the plant should be via existing service roads with upgrading to
allow heavy equipment, but roads should not be open to the general
public. Buffer zones, especially of evergreens, can protect wild-
life from noise.

Construction: The sponsor must perform the coastal construction
with the utmost care to protect adjacent aquatic and terrestrial areas.
The scheduling of construction must avoid sensitive periods of wildlife,
including breeding/spawning, rearing of young, etc. Operations of heavy
equipment must be performed to protect fragile environments, such as
barrier beaches, wetlands, and clam/mud flats. In many cases, particularly
landfalls, mats can reduce the impact of heavy equipment operations.
Construction near wetlands or on the upland must involve stringent
erosion control methods to prevent silt from entering streams and rivers
where there could be interference with fish reproduction.

Dredging of pipeline trenches in coastal areas should be done in a
manner which will minimize turbidity and sedimentation, such as the
employment of sediment screens and other techniques. If pipeline trenches
are dug through wetlands, excavated material should be replaced in the
trench instead of along the sides where it can interrupt water flow and
change circulation patterns, salinity, temperature, and other factors.
In addition new fill materials should be added where necessary to keep
the elevation above the newly installed pipe the same as the surrounding
wetland.

Operation: With the necessity to handle flammable gas and associated
petroleum hydrocarbons, operations at the plant must be performed to
prevent accidental releases and ignitions to protect human and wildlife
environments. In addition emergency procedures should be practiced
routinely so personnel can respond quickly and appropriately in time of
need.

Regulatory Factors

Where siting flexibility allows selection of a site with suitable
zoning, outside the immediate coastal zone, both state and local permits
and Federal permits required for a gas processing plant may be minimal.
Pipelines and related permits and construction standards are discussed
in Section 2.2.3.

Pollution control regulations under the Federal Water Pollution
Control Act and the Clean Air Act will also affect plant design. Permits
are administered by both state agencies and the U.S. Environmental
Protection Agency.

210

Development Strategy

There is no fixed quantity of gas which justifies the development
of a field (although 2 million cubic feet per day is generally sufficient).
The major factors which determine whether a gas processing plant is
built are the volume of gas discovered, the "richness" of the gas measured
in gallons of liquid petroleum per 1,000 cubic feet of gas, and costs
[26]. The richer a formation is in liquid hydrocarbons, the smaller a
find needs to be in order to justify the construction of a gas processing
plant. Gas must be found in sufficient quantity to justify the cost of
processing, transporting, and distributing it. If an insufficient
amount of gas is discovered, the well may be capped, or the gas may be
reinjected into the well to maintain the formation pressure if commercial
quantities of oil can be produced.

Gas is usually sold to a gas company at the well. The gas company
is then responsible for constructing a gas pipeline. The oil company,
which retains the rights to the liquid hydrocarbons in the gas stream,
is responsible for constructing the gas processing plant. The cost of a
gas processing plant depends on the quantity of gas, the richness of the
gas, the degree of extraction of the key component (methane) and the
number of separate products that are fractionated and stored [26].

211

2.4.4 Liquefied Natural Gas (LNG) Processing Plants

There are two types of Liquefied Natural Gas (LNG) processing
plants. The liquefaction plant takes natural gas from a gas field,
cools and compresses it, and then transfers the LNG to a specialized
tanker for transport. The regasification plant receives LNG from the
tanker, heats and vaporizes it and then sends the gas to a natural gas
pipeline distribution system. The LNG tanker is an elaborate ship with
a series of large self-contained tanks, which store the LNG under
pressure and cold temperatures for the oceanic voyage to the regasification
plant. LNG tankers are not designed to carry crude oil. Tankers currently
being built can carry 785,000 barrels (125,000 cubic meters) of LNG,
which is equivalent to 2.5 billion cubic feet of natural gas. The
vessels measure over 900 feet in length, with a draft of more than 35
feet. They are approximately the size of a large aircraft carrier or a
100,000 ton displacement oil tanker [51]. (See Figure 43)

Figure 43. Liquefied natural gas (LNG) processing plants, project
implementation schedule.

INVESTMENT COMMITMENTS:

Site Purchase

Site Option(s
Taken

Start of
Construction

YEARS""

PERMIT ACQUISITIONS:

Begin
O Processing
Operations

Acquisition of Use and
Location Permits

Operating Permits

Preconstruction Permits
(Includes EIS)

This involved system allows the utilization of gas from distant
fields which are not able to reach markets by the construction of
pipeline systems. Liquefaction, transport and regasification, as
expensive operations, can only be economically viable where demand for
gas is high and domestic supply is limited. Such a situation exists in

212

the United States where demand has been increasing and domestic gas
production has been declining in recent years. The United States can
expect to see additional regasification facilities, with the possibility
of liquefaction plants in Alaska. Currently, an LNG liquefaction plant
is under construction in Indonesia with its counterpart regasification
plant proposed for Oxnard, California. Other LNG regasification plants
nearing completion are at Cove Point, Maryland, and Elba Island, Georgia

Description

An LNG regasification plant generally has an elevated pier or
trestle as much as 6,500 feet long to receive liquefied gas from the LNG
tankers berthed offshore. (Cove Point has a tunnel.) The LNG is delivered
to two or more storage tanks of 3 million cubic foot capacity before
processing to return it to a gaseous state. The proposed LNG facility
and trestle at Oxnard, California, consists of 218 acres, with 30 acres
to be initially developed (expected to reach a maximum of 46 acres).
The remaining acreage is either landscaped or undeveloped. The tanks are
to be 80 feet high and 239 feet across. A reinforced concrete dike
around each tank will be able to contain its entire contents. From the
regasification plant pipelines carry vaporized gas to the gas company's
existing distribution system [52].

Site Requirements

Due to the possibility of an accidental explosion, LNG liquefaction
and regasification plants are generally located to avoid populated areas
and should have substantial acreages of buffer, preferably wooded,
between the plant and other land uses. The site size may extend to
approximately 1,000 acres. Plant functions should be located no closer
than one-third of a mile from neighboring roads, buildings, etc. and
preferably should be further. The proposed site for an LNG facility
must be level and capable of supporting heavy-weight storage tanks.

The plants are typically located on the coast and have an
ocean connection due to the necessary tanker transport. While con-
venient, the coastal location is not a necessity. The processes which
are conducted in either a liquefaction or regasification plant could
occur at an inland site and probably at a greatly reduced cost in terms
of acquisition. This may be particularly true where a large buffer is
part of the facility plan. It is necessary to have a navigational
channel and a marine terminal. Tanker drafts may exceed 35 feet so the
terminal may have to be located some distance offshore or access channels
and turning basins may be dredged. Sandy areas will make dredging
operations easier compared to rocky seabottoms.

213

Construction/Installation

The construction of an onshore liquefaction or regasification plant
requires the clearing of land in the immediate vicinity of the plant and
making the topography as level as possible. This will require the use
of heavy earth-moving equipment. With the selection of a coastal site,
there is an unusually high probability that low-lying wetlands will be
excavated and filled with sand and/or gravel to make a firm working
surface. Storage tanks will have to be constructed with protective berm
enclosures to contain fluids in case of leaks or ruptures.

A marine terminal will be constructed for unloading the LNG ship.
If it is to be a close-in dock, there may be a requirement for a navigation
channel to approximately 40 feet deep and a turning basin about four
times the ship's length or 3,600 feet. If a channel and turning
basin arenot readily available, the sponsor is likely to build a long
pipeline or trestle out to a depth adequate for LNG ships. Construction
of an underwater pipeline would involve underwater trenching and filling.
In some cases, ship-to-shore pipelines will be on a trestle, (Oxnard,
California) or enclosed in a tunnel (Cove Point, Maryland), which could
also serve to transport personnel between the plant and the marine
terminal [53].

Operation

In receiving natural gas from an offshore gas field, a liquefaction
plant first removes impurities and then cools the gas under pressure to
approximately -250° F. This causes a reduction in volume greater than
600 times and converts the gas into a liquid. From this point until the
time of regasification the gas must be maintained under constant low
temperatures and high pressures. The liquefied gas is held in storage
tanks until it can be loaded onto an LNG tanker for shipment. The basic
constituents of a liquefaction plant are compressors and cooling apparatus,
storage tanks, a marine terminal, underwater pipelines from the gas
field, blowers, pumps, metering systems, administrative offices and
maintenance buildings.

The regasification facility is essentially the reverse of a
liquefaction plant having many of the same components, such as the
marine terminal pumps and underwater pipelines. The difference is the
presence of vaporizers which heat and reconvert the LNG to a gaseous
state. A typical regasification procedure is described by the following
and illustrated in Figures 44 and 45.

1. LNG tanker docks at the marine terminal.

2. Articulated unloading arms attach to ship.

214

3. Ship's pumps move LN6 through underwater,
buried pipeline to storage tanks of
shoreside regasification facility.

4. Blowers transfer storage tank vapors back to
ship to maintain positive pressure in ship's
tank/or to be reconverted to LNG.

5. From storage tanks LNG is pumped by booster
pumps to plant at 50 pounds per square inch
(psi).

6. Primary pumps raise the pressure of the LNG
to approximately 100 psi.

7. Secondary pumps increase the pressure to
1,250 psi.

8. LNG enters the water bath, gas fired vaporizer
where it is converted to 60° F, 1,200 psi
pipeline gas.

9. The natural gas is metered and placed into
a gas company's pipeline for distribution
to its customers.

The proposed LNG plant at Oxnard will initially process 522 million
cubic feet/day (MMCFD) and expect about 75 ship arrivals annually. This
averages to one ship every 5 days. At a maximum potential capacity of 4
billion cubic feet/day 565 ship arrivals may be expected, averaging
three ships every two days.

Community Effects

LNG liquefaction and regasification plants are located near the
water and modify natural gas to make it more economical to transport.
Conditions under which plants are built, therefore, are dictated by
large sources of supply and large markets. The plant is located in a
flat, shorefront site, preferably in rural areas, and employs very few
skilled technicians after construction.

Employment: The average work force to construct an LNG regasificatic
plant with a billion cubic feet/day capacity is approximately 600
workers. The Cove Point, Maryland, plant of Columbia LNG Corporation
required approximately 900 workers at peak levels, but this increase was
primarily to complete the tunnel to the offshore discharge terminal, an
unusual requirement.

The operating staff of an LNG plant with this capacity is approximate
100 people. The three major job categories are operators, maintenance,

215

Figure 44. LNG vaporizer (Source: Reference 53).

LNG vaporizer

Gas inlet

Combustion chamber

Covet plate

Water travel

Water level

and unskilled utility workers. The Columbia LNG Corporation estimates
approximately 50 percent of the operational employees in this
will be hired locally and the remainder will migrate into the
contrast, another major LNG plant in the United States, under
in Savannah, Georgia, will probably be able to fulfill almost
employment demands within the Savannah area [55].

rural area
area. By
construction
all its

Effects on Living Resources

LNG liquefaction and regasification plants have the following
characteristics of particular fish and wildlife concern: (1) waterfront
location; (2) deepwater marine terminal; (3) navigation channel, berths
and turning basin; (4) cleared, level land; (5) offshore/onshore pipelines;
(6) LNG processing and storage equipment; anci (7) access roads.

216

Figure 45. Flow diagram of Elba Island LNG facility
(Source: Reference 54).

Flow diagram of Elba Island facility.

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Location: While approximately 50 acres is required for LNG equipment,
large amounts of additional land are usually purchased for a safety
buffer. The potential exists for explosion at a facility of this type,
so the sponsor must attempt to locate plants some distance from populated
areas. Special care must be taken to reduce adverse environmental
effects on aquatic and terrestrial wildlife and on endangered species
habitats. The ecological problems associated with LNG processing plants
are primarily a result of the sponsor's desire to locate the facility at
a coastal site to reduce costs of pipeline construction. While LNG must
be unloaded from an LNG tanker at a marine terminal, the actual processing
of the gas can occur on upland areas some distance from the unloading
operation. To facilitate LNG deep-draft vessels the marine terminal may
be located some distance from shore and connected by pier or tunnel to
the onshore processing site.

217

Relatively flat land is needed for the installation of LN6 refrig-
eration, compression, regasification, and storage equipment. With level
shorefront land zoned for industry at a premium along the coast, the
chances increase that wetlands will be filled to obtain the desired ele-
vation. If this is done important spawning/breeding and rearing areas of
a variety of fish and wildlife will be lost. In addition, water circula-
tion will be altered, perhaps leading to changes in salinity, temperature,
oxygen and other measures of water quality.

Design: With the possibility that LNG tankers would be situated in
deep waters distant from shore, provisions should be made for boat traffic
to pass safely and easily without traveling around the end of the pier.
This will reduce the potential for boating accidents. The pier design
should utilize open piles and avoid a solid-fill structure. The latter
type alters the natural configuration of the shoreline and robs areas
downshore of needed sand by interrupting littoral drift. In addition,
solid-fill structures tend to disrupt water currents. This may lead to
a significantly changed fish and wildlife habitat.

The need for dredging adequate navigation channels and a turning
basin will cause problems of turbidity and sedimentation, which may lead
to the smothering of clams, corals and other organisms. Oxygen depletion
is also associated with dredging. Channels should be designed to limit
the amount of initial and maintenance dredging. Firm bottom soils will
release fewer sediments to the water than loose, unconsoldiated types,
which will require more frequent maintenance dredging.

Existing service roads should be maintained to allow heavy equip-
ment, but roads should not be open to the general public. If a water-
front site is selected, the feasibility of transporting heavy processing
and construction equipment by sea should be explored. Every storage
tank should have its own access by a service road to allow safe and
effective fire protection. Dikes surrounding tanks should not be tra-
versed by service vehicles and the top of the dike should not be utilized
as a service road.

Construction: The sponsor must perform the coastal construction
with the utmost care to protect adjacent aquatic and terrestrial areas.
The scheduling of construction must avoid sensitive periods of species,
including breeding/spawning, rearing of young, etc. Operations of heavy
equipment must be performed to protect fragile environments, such as
barrier beaches, wetlands and clam/mud flats. In many cases, particu-
larly near wetlands, mats can reduce the impact of heavy equipment
operations. Construction must involve stringent erosion control methods
to prevent silt from entering streams and rivers where it could inter-
fere with fish reproduction.

218

If a tunnel is not constructed, the marine terminal should be
connected by an open pile pier with floats instead of a sheet steel
bulkhead. In the construction of steel bulkheads, shores are often
dredged to create a berth and to obtain fill to place behind the bulkhead.
This alters the natural configuration of the shoreline and robs areas
downshore of needed sand by interrupting littoral drift. In addition
solid fill structures tend to intercept, divert and disperse water
currents. This diversion may decrease available food supply and change
water parameters, such as salinity, oxygen, etc., leading to a significantly
altered fish and wildlife habitat. If a tunnel is constructed a proper
spoil disposal site must be selected to avoid filling wetlands and
prevent seepage of contaminants into adjacent areas.

With the necessity for the onshore LNG site to be relatively
flat, a major construction component will entail heavy equipment operations
to level the land. This requirement will cause large acreages to be
cleared of vegetation and will cause a drastic change in the microclimate
of the area. Species which previously occupied the area will now find
that area uninhabitable. Also, with the vegetation removed there is the
possibility of erosion if appropriate measures are not taken for control.
Without proper control there may be excessive sedimentation into streams
and rivers producing degraded fish habitats.

Operation: Loading and unloading of liquefied natural gas must be
performed with the utmost care to avoid human error accidents. In
addition, contingency plans should be practiced routinely so personnel
can respond quickly and appropriately.

Constant communication must be maintained between onshore operations
and the offshore LNG tanker so sudden changes of temperature, pressure
and other unexpected events can be corrected. This is in addition to
automatic devices installed for safety purposes.

Regulatory Factors

State and local regulatory factors may exert an important influence
on the location of LNG facilities. Federal jurisdiction over interstate
gas pipeline facilities is also discussed in Section 2.2.4.

Special Federal regulations also set standards for Liquefied Natural
Gas Systems (49 C.F.R., Part 192 -- Amendment 192-10). The Occupational
Safety and Health Act, Clean Air Act, and Federal Water Pollution Control
Act will also affect the design and operations of portions of the facility.

The specialized transportation facilities required in association
with LNG Processing Plants are also subject to Federal control, primarily
through the U.S. Coast Guard (See 2.2.5 -- Tanker Operations), but also
through other agencies such as the American Bureau of Shipping and the
Federal Maritime Commission.

219

Development Strategy

The strategy behind the importation of liquefied natural gas is
that it can compete economically with gas from domestic fields, in spite
of large capital expenditures for processing plants and the highly
specialized LNG tankers, which carry cargo in only one direction. The
costs of two conversions, plus transportation should not exceed the
price of gas that might be available through domestic gas pipelines.
With declining United States reserves, the importation of LNG may be the
only way to maintain adequate gas supplies. Liquefaction plants being
designed are expected to process three billion cubic feet of gas per day
[56], whereas the economic minimum may be near 175 million cubic feet
per day [57].

To reduce some of the steps in getting LNG into the gas pipelines
one company has proposed an offshore, floating liquefaction plant.
Although none of these have been built, this type of structure could be
moved to an offshore gas field, liquefy the gas and load LNG directly
onto a tanker as illustrated in Figure 46. There would be no need
either for a prohibitively expensive offshore gas pipeline or for an
onshore liquefaction plant, thus smaller gas fields could be developed
that otherwise would prove uneconomic due to the above costs. With its
mobility, the floating, liquefaction plant could be moved to utilize
those resources.

220

Figure 46. Proposed design of offshore LNG plant - natural
gas liquefaction on a semi -submersible storage and loading
platform (Source: Reference 58).

tm^

221

REFERENCES

1. University of Oklahoma. May 1975. Energy Alternatives: A Comparative

Analysis. For Council on Environmental Quality. Science and Pub-
lic Policy Programs, Tlorman, Oklahoma.

2. Exxon Corporation. September 1975. Enerny Outlook, 1975-90.

Special ftudy. New York, TJew York.

3. Miller, B. et al . 1975. Geological Estimates of Undiscovered

Recoverable Oil and Has Resources in the United States. United
States Geological Survey, Circular 725. Washington, D.C.

4. United States flaritime Administration. 1975. Final Environmental

Impact Statement, Tanker Construction Program. National Technical
Information Service Report No. EIS-730F. Washington, D.C.

5. McCulloh, T. H. 1973. Oil and Gas. U.S. Mineral Resources.

United States Geological Survey Professional Paper 820.
Washington, D.C.

6. Berryhill, H.L. 1974. Worldwide Search for Petroleum Offshore.

In Status Report for the Quarter Century, 1947-72. United
States Geolooical Survey. Circular 694. Washington, D.C.

7. League of Women Voters. 1976. The Onshore Impact of Offshore Oil.

Publication No. 661. Washington, D.C.

8. Schlee, J., J. C. Behrendt, R.E. Mattick and P.T. Taylor. 1975.

Structure of Continental Marr)in Off Mid Atlantic States
(Baltimore Canyon Trough). United States Geological Survey, Open
File Report 75-60. Washington, D.C.

9. No author. January 19, 1976. U.S. Offshore Frontiers: How

Promising Are They? Oil and Gas Journal. Vol. 73, #3.
Tulsa, p. 19.

10. Ibid.

11. op. cit. United States Maritime Administration, 1975. Washington,

D.C.

12. U.S. Department of the Interior, Bureau of Land Management.

January 1977. Revised OCS Leasing Schedule. Int: 1392-77.
Bureau of Land Management, Washington, D.C.

13. Johnson, L.P. January 1975. The High Cost of Offshore Oil. Oil

and Gas Energy, Vol. 73, #1. Houston, Texas, pp. 2-24.

14. Flood, L.B. 1975. The Outlook for the Offshore Oil Service Industry.

1975-90. First National Bank of Boston. Boston, Massachusetts.

15. National Petroleum Council. March 1975. Ocean Petroleum Resources.

#15. Washington, D.C.

222

16. Woods Hole Oceanographic Institution. April 1976. Effects on

Comiriercial Fishing of Petroleum Development off the Northeastern
United States. Marine Policy and Ocean Management Program.
Woods Hole, Massachusetts.

17. op. cit. University of Oklahoma. 1975. Norman, Oklahoma, p. 3-14.

18. op. cit. University of Oklahoma. 1975. Norman, Oklahoma, p. 3-16.

19. BDM Corporation. 1975. A Studv of New Use Demands on the Coastal

Zone and Offshore Areas of New Jersey and Delaware. Vienna,
Virginia.

20. BDM Corporation. December 1975. Final Report. Federal Legal and

Administrative/Regulatory Aspects of Offshore Development, Appendix I
Prepared for Office of Technology Assessment, U.S. Congress. Con-
tract OTA-C-8. BDM/W-75-149-TR. Vienna, Virginia.

21. U.S. Department of the Interior, Bureau of Land Management. May 1976.

The Outer Continental Shelf Oil and Gas Development Process: A Back-
ground Paper for State Planners and Managers. Bureau of Land
Management, Washington, D.C.

22. Tetra-Tech, Inc. 1973. The Effect of Natural Phenomenon on PCS Gas

and Oil Development. Prepared for the Council on Environmental
Quality. Contract No. EQ4AC070. Washington, D.C.

23 C.C. taylor, EXXON Company. 1975. Status of Completion/Production
Technology for the Gulf of Alaska and the Atlantic Coast Offshore
Petroleum Operations. Presented at the Resources for the Future.
Inc. Seminar. Washington, D.C, December 5-6, 1973. Conducted
for the Council on Environmental Quality under Contract No.
EQ4AG003. Washington, D.C.

24. McDermott and Company, Inc. 1975. The Jaramac, Vol. 19. New

Orleans, Louisiana.

25. Resource Planning Associates. 1975. Identification and Analysis of

Mid-Atlantic Onshore OCS Impacts. Cambridge, Massachusetts.

26. New England River Basins Commission - RALI Project. 1976. Onshore

Facilities Related to Offshore Oil and Gas - Factbook. Boston,
Massachusetts.

27. Pipeline Industry. September 1974. Direction Drilling Adapted for

Pipe Line River Crossings. Pipeline Industry. Volume 41, Number 3.
Houston, Texas.

28. Florida Energy Office and State University System of Florida.

December 1975. Florida Coastla Policy Study: The Impact of
Offshore Oil Development. Tallahassee, Florida.

223

29. United States Department of Transportation, U.S. Coast Guard.

1976. Draft Environmental Impact Statement: LOOP Deepwater Port
License Application. Three volumes. U.S. Coast Guard, Office
of flarine Environment and Systems, Washington, D.C.

30. United States Department of Transportation, U.S. Coast Guard.

1976. Draft Environmental Impact State: Seadock Deepwater Port
License Application. Three volumes. U.S. Coast Guard, Office
of riarine Environment and Systems, Washington, D.C.

31. Femenia, Jose. June 1973. Development of a Pollution-Free Cargo Tank

Cleaning System for Use on Board Tankers. State University of New
York Maritime College. New York Sea Grant Program, Albany, New York.

32. United States Department of the Interior, U.S. Geological Survey. 1976.

An Oil Spill Risk Analysis for the Mid Atlantic Outer Continental
Shelf. Open File Report 76-451. U.S. Geological Survey, Washington,
D.C.

33. Lasday, Albert H. 1976. Oil Spills - Historical Review and

Characteristics. Unpublished. Seminar for the United States
Fish and Wildlife Service and American Petroleum Institute, New
Orleans, Louisiana, April 26-27, 1976.

34. Alaska Consultants, Inc. 1976. Marine Services Bases. (Draft Report).

Prepared for the Division of Community Planning. Department of
Community and Regional Affairs, State of Alaska. Juneau, Alaska.

35. Obtained from advertising brochure of Arthur Levy and Company.

36. U.S. Department of the Interior, Bureau of Land Management. 1976.

Final Environmental Statement, OCS Sale Number 40. Bureau of Land
Management, Wasfiin^ton, D.C.

37. Personal communication with William Rice of Brown and Root. Houston,

Texas, February 8, 1977.

30. Personal communication with Robert Guff. February 8, 1977. United

States Geological Survey, Conservation Division. Anchorage, Alaska.

39. Urban Pathfinders, Inc. February, 1975. Brown and Root Impact Study.

Houston, Texas.

40. New England Regional Commission. November 1975. Petroleum Development

in New England: Economic and Environmental Considerations. Volume II
Boston, Massachusetts.

224

41. Huston, J.W. and W.C. Huston. May 1976. Techniques for Reducing

Turbidity Associated with Present Dredging Procedures and
Operations. John Huston, Inc. U.S. Army Engineers Waterways
Dredged Material Research Program. Contract Number DAC W39-75-C-
0073. Vicksburg, Mississippi.

42. January 1, 1976. Oil and Gas Journal.

43. California Coastal Zone Conservation Commission. 1975. California

Coastal Plan. Sacramento, California.

44. Franco Alvaro. August 9, 1976. Tulsa Refinery Features Flexibility in

in FCC Output. Oil and Gas Journal. Vol. 74, #32.

45. Boykin, R.E. September 1972. Petrochemical Industry of Texas and

the Gulf of Mexico. Department of flarine Resources Information,
Center for Marine Resources, Texas A&f1 University.

46. Federal Energy Office. 1974. Trends in Refinery Capacity and

Utilization. Superintendent of Documents, U.S. Government Printing
Office, Washington, D.C.

47. U.S. Department of the Interior, Bureau of Land Management. 1976.

Final Environmental Statement, OCS Sale Number 41. Bureau of Land
flanagement, Washington, D.C.

48. Resource Planning Associates. 1973. Potential Onshore Effects of

Oil and Gas Production on the Atlantic and Gulf of Alaska Outer
Continental Shelf, Industry Development Appendices, Appendix IV' --
Petrochemicals. Prepared for the Council on Environmental Quality.
Resources Planning Associates, Cambridge, Massachusetts.

49. Council on Environmental Quality. April 1974. OCS Oil and Gas - An

Environmental Assessment. Volume 4. Washington, D.C.

50. New England River Basins Commission - RALI Project. 1976. Technical

Update 4 — Onshore Facilities Related to Offshore Oil and Gas.
Boston, Massachusetts.

51. Hale, D. 1976. First U.S. LNG Import Program Nearinq as El Paso's

LNG Carrier Number Mounts. Pipeline and Gas Journal. Vol. 203, #7.
Dallas, Texas.

52. Socio-Economic Systems, Inc. 1976. Draft Environmental Impact

Report for the Proposed Oxnard LNG Facilities. Prepared for
Western LNG Terminal Company. Socio-Economic Systems, Inc.,
Los Angeles, California.

53. Levy, M.M. June 21, 1976. LNG Terminal Will Ease Gas Shortage.

The Oil and Gas Journal. Vol. 74, #25. p. 133.

225

54. Alexander, J. 3. and N.T . Williams. June 1976. Elba Island LNG

Facility on Schedule, Completion Set for Late 1977. Pipeline
and Gas Journal. Vol. 203, #7. Dallas, Texas.

55. Personal communications with n. Levy. Columbia LNG Corporation.

Cove Point, Maryland.

56. El Paso Alaska Company. September 1974. Application of El Paso

Alaska Company for a Certificate of Public Convenience and
Environmental Report. Volume III. Prepared for submission to
the Federal Pov/er Commission, Washington, D.C.

57. Canada Transportationand Development Agency. June 1974. Arctic Oil

and Gas by Rail . Ottawa, Ontario, Canada.

58. Obtained from advertisement brochure of Preussag AG, Linde AG,

Technigas. Hannover, Germany.

liU.S. GOVERNMENT PRINTING OFFICE: 197 8 -71+5-U21/ i+U 8 5 REGION NO. 4

226

PLATE I

A hypothetical (not to scale) layout of offshore and
onshore components of an oil/gas recovery system
constructed so as to show the type of units that could
be used in a variety of OCS developments. [NOTE:
This plate was furnished by courtesy of J. Ray
McDermott Company for illustrative purposes only; no
endorsement by the U.S. Fish and Wildlife Service nor
its contractor is intended or should be implied.]
Source: Reference 24.

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